U.S. patent application number 12/239678 was filed with the patent office on 2009-05-14 for state and topology processor.
Invention is credited to Marcos A. Donolo, Armando Guzman-Casillas, Edmund O. Schweitzer, III.
Application Number | 20090125158 12/239678 |
Document ID | / |
Family ID | 40549806 |
Filed Date | 2009-05-14 |
United States Patent
Application |
20090125158 |
Kind Code |
A1 |
Schweitzer, III; Edmund O. ;
et al. |
May 14, 2009 |
STATE AND TOPOLOGY PROCESSOR
Abstract
A State and Topology Processor (STP) may be communicatively
coupled to one or more intelligent electronic devices (IEDs)
communicatively coupled to a electrical power system to obtain one
or more current measurements, voltage measurements, and dynamic
topology data therefrom. The STP may receive the measurement data
and may determine a current topology and a voltage topology
therefrom. A current processor may use the current topology and the
current measurements to refine the measurements, perform KCL,
unbalance, symmetrical component, and consistency checks on the
electrical power system. The voltage processor may use the voltage
topology and the voltage measurements to perform similar checks on
the electrical power system. One or more alarms may be generated
responsive to the checks. The data may be displayed to a user in a
display of a human machine interface and/or may be transmitted to a
user programmable task module, and/or an external control unit.
Inventors: |
Schweitzer, III; Edmund O.;
(Pullman, WA) ; Donolo; Marcos A.; (Pullman,
WA) ; Guzman-Casillas; Armando; (Pullman,
WA) |
Correspondence
Address: |
Schweitzer Engineering Laboratories, Inc.;Richard Edge
2350 NE HOPKINS COURT
PULLMAN
WA
99163-5603
US
|
Family ID: |
40549806 |
Appl. No.: |
12/239678 |
Filed: |
September 26, 2008 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60978711 |
Oct 9, 2007 |
|
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Current U.S.
Class: |
700/293 ;
700/286; 700/292; 700/297; 700/298; 715/772 |
Current CPC
Class: |
Y02E 40/70 20130101;
Y04S 10/00 20130101; Y04S 10/22 20130101; G01R 19/2513 20130101;
Y02E 60/00 20130101 |
Class at
Publication: |
700/293 ;
700/286; 700/297; 700/292; 700/298; 715/772 |
International
Class: |
G06F 1/28 20060101
G06F001/28; G06F 3/048 20060101 G06F003/048 |
Claims
1. A system for monitoring an electrical power system, comprising:
a communication module communicatively coupled to a plurality of
intelligent electronic devices (IEDs), wherein each IED is
communicatively coupled to a portion of the electrical power
system; and a topology processor communicatively coupled to the
communication module and comprising a static topology of the
electrical power system, wherein the topology processor is
configured to receive dynamic topology data from the IEDs and to
determine an operating topology of the electrical power system
using the static topology and the dynamic topology data.
2. The system of claim 1, wherein electrical power system comprises
a plurality of nodes connected by one or more branches.
3. The system of claim 2, wherein one or more of the plurality of
IEDs are configured to obtain current measurements on one or more
of the branches of the electrical power system, wherein one or more
of the plurality of IEDs are configured to obtain voltage
measurements on one or more of the nodes of the electrical power
system, and wherein one or more of the plurality of IEDs are
configured to obtain dynamic topology data of the electrical power
system.
4. The system of claim 3, wherein the plurality of IEDs are
configured to transmit current measurements, voltage measurements,
and/or dynamic topology data to topology processor through the
communication module.
5. The system of claim 4, wherein the current measurements are time
aligned using a timestamp.
6. The system of claim 4, wherein the voltage measurements are time
aligned using a timestamp.
7. The system of claim 4, wherein the current measurements, the
voltage measurements, and the dynamic topology data are time
aligned using one or more timestamps.
8. The system of claim 4, wherein the current measurements and the
voltage measurements comprise synchrophasors.
9. The system of claim 8, wherein one or more of the IEDs comprises
an IEEE C37.118 device and the communication module comprises an
IEEE C37.118 device.
10. The system of claim 4, wherein the operating topology comprises
a current topology comprising current branch-to-node data array and
current merged node data array.
11. The system of claim 10, wherein the topology processor is
configured to merge nodes according to the closed branches in the
current branch-to-node data using the dynamic topology data.
12. The system of claim 11, further comprising a current processor
communicatively coupled to the communication module and the
topology processor.
13. The system of claim 12, wherein the current topology comprises
a current correction factor, and wherein the current processor is
configured to normalize a particular current measurement using the
current correction factor.
14. The system of claim 13, wherein the current correction factor
normalizes the particular current measurement relative to one
selected from the group consisting of: a turn ratio of a current
transformer used to obtain the particular current measurement; an
orientation of the particular current measurement in the current
topology; a phase shift; a magnitude adjustment; and combinations
thereof.
15. The system of claim 12, wherein the current processor is
configured to perform a current consistency check on a particular
branch in the current branch-to-node data array, and wherein to
perform a current consistency check on a particular branch, the
current processor is configured to calculate a median or mean value
of a plurality of current measurements on the branch, to calculate
a difference between each current measurement and the median or
mean value, to compare each difference to a user-defined current
consistency threshold, and to set a current consistency alarm on
the branch if one or more of the differences exceeds the
user-defined current consistency threshold.
16. The system of claim 15, wherein the current processor is
configured to perform the current consistency check on each phase
of three-phase current measurements of the particular branch in the
current branch-to-node data array.
17. The system of claim 12, wherein the current processor is
configured to perform an unbalance check on a particular branch in
the current branch-to-node data array, and wherein to perform an
unbalance check on a particular branch, the current processor is
configured to calculate an unbalance based on a ratio of a
magnitude of a selected phase of a particular current measurement
at the particular branch to a reference current, and to assert an
unbalance alarm on the selected phase of the particular current
measurement if the unbalance exceeds a user-defined current
unbalance threshold.
18. The system of claim 17, wherein the reference current is a
median value of a plurality of current measurements at the
particular branch.
19. The system of claim 12, wherein the current processor is
configured to calculate symmetrical components of one or more
current measurements on a particular branch in the current
branch-to-node data array, and wherein the current processor is
configured to assert a symmetrical current alarm on the particular
branch if one or more of the symmetrical components exceeds a
user-defined current symmetrical component threshold.
20. The system of claim 12, wherein the current topology comprises
a current branch to node data array and a current merged node data
array, wherein the current branch to node data array includes
information concerning interconnection of the nodes, and wherein
the current merged node data array includes information concerning
a number of nodes and node information within the group.
21. The system of claim 20, wherein the current processor is
configured to perform a Kirchhoff's Current Law (KCL) check on an
entry in the current merged node data array, and wherein to perform
a KCL check on a particular entry in the current merged node array,
the current processor is configured to sum the current measurements
of each branch in a branch list of the particular entry, and to set
a KCL status on the particular entry if the sum does not exceed a
user-defined KCL threshold.
22. The system of claim 21, wherein the current processor is
configured to perform the KCL check on each phase of three-phase
current measurements of the particular entry in the current merged
node data array.
23. The system of claim 21, wherein the current processor is
configured to refine the current measurements of the branch list of
the particular entry in the current merged node data array using
error minimization if the current measurements of the particular
entry the current merged node data array satisfy the user-defined
KCL threshold.
24. The system of claim 22, wherein the error minimization for n
current measurements is: I i = A i - j = ? ? ? , i = , 2 , , n
##EQU00008## ? indicates text missing or illegible when filed
##EQU00008.2##
25. The system of claim 23, wherein the current measurements
comprise three-phase current measurements, and wherein the current
processor is configured to refine each phase of the three-phase
current measurements.
26. The system of claim 4, wherein the operating topology comprises
a voltage topology, and wherein the voltage topology comprises a
voltage merged node data array and a voltage branch-to-node data
array.
27. The system of claim 26, wherein the topology processor is
configured to merge nodes according to closed branches in the
voltage branch-to-node data array using the dynamic topology
data.
28. The system of claim 27, wherein the system further comprises a
voltage processor communicatively coupled to the communications
module and the topology processor.
29. The system of claim 28, wherein the voltage topology comprises
a voltage measurement correction factor, and wherein the voltage
processor is configured to normalize a voltage measurement using
the voltage measurement correction factor.
30. The system of claim 29, wherein the voltage correction factor
normalizes the voltage measurement relative to one selected from
the group consisting of: a turn ratio of a voltage transformer used
to obtained the voltage measurement; a voltage base value; a
magnitude adjustment; a phase shift; and combinations thereof.
31. The system of claim 28, wherein the voltage topology comprises
a voltage node data array, wherein each entry in the voltage node
data array comprises nodes within the node group.
32. The system of claim 31, wherein the voltage processor is
configured to perform a voltage consistency check on a particular
entry in the voltage node data array, and wherein to perform a
voltage consistency check on a particular entry in the voltage node
data array, the voltage processor is configured to calculate a
median voltage of a plurality of voltage measurements on the nodes
of the particular entry, to calculate a difference between each of
the plurality of voltage measurements on the nodes of the
particular entry and the median or mean voltage, and to set a
voltage consistency alarm on the particular voltage node group if
one or more of the differences exceeds a user-defined voltage
consistency threshold.
33. The system of claim 32, wherein the voltage processor is
configured to perform the voltage consistency check on each phase
of three-phase voltage measurements of the particular entry in the
voltage node data array.
34. The system of claim 32, wherein the voltage processor is
configured to refine a voltage measurement of the particular entry
in the voltage node group.
35. The system of claim 34, wherein to refine a voltage measurement
of the particular entry in the voltage node group, the voltage
processor is configured to set the voltage measurement to the
median voltage of the particular entry in the voltage node
group.
36. The system of claim 28, wherein the voltage processor is
configured to calculate symmetrical components of one or more
voltage measurements on a particular node in the voltage
branch-to-node data array, and wherein the voltage processor is
configured to assert a symmetrical voltage alarm on the particular
node if one or more of the symmetrical components exceeds a
corresponding user-defined symmetrical component threshold.
37. The system of claim 1, further comprising a phase measurement
and control unit (PMCU).
38. The system of claim 37, wherein the PMCU is configured to
transmit to an external device one selected from the group
consisting of: current measurements; refined current measurements;
voltage measurements; refined voltage measurements; and
combinations thereof.
39. The system of claim 38, wherein the current measurements and/or
voltage measurements are time aligned.
40. The system of claim 38, wherein the current measurements and/or
voltage measurements comprise synchrophasors.
41. The system of claim 40, wherein the PMCU comprises a IEEE
C37.118 device and wherein the external device comprises a IEEE
C37.118 device.
42. The system of claim 37, wherein the PCMU is configured to
transmit to an external device one or more alarms and/or trip
signals generated responsive to the current measurements and/or the
voltage measurements.
43. The system of claim 1, further comprising a user programmable
task module communicatively coupled to the current processor and
the voltage processor to receive one or more current measurements
and/or refined current measurements, and/or one or more voltage
measurements and/or refined voltage measurements therefrom, wherein
the user programmable task module is configurable by a user to
perform one or more user programmable tasks using the one or more
current measurements and/or one or more voltage measurements.
44. A computer-readable storage medium comprising instructions to
cause a computing device to perform a method for monitoring an
electrical power system comprising a plurality of nodes
interconnected by a one or more branches having a plurality of
intelligent electronic devices (IEDs) communicatively coupled
thereto, the method comprising: storing a static topology of the
electrical power system; receiving from the plurality of IEDs a
plurality of current measurements obtained from one or more of the
branches of the electrical power system, a plurality of voltage
measurements obtained from one or more of the nodes of the
electrical power system and dynamic topology data; and determining
an operating topology of the electrical power system using the
static topology of the electrical power system and the dynamic
topology data received from the plurality of IEDs, wherein the
operating topology comprises a current topology and a voltage
topology.
45. The computer-readable storage medium of claim 44, wherein the
dynamic topology data comprises status of breakers and
disconnects.
46. The computer-readable storage medium of claim 44, wherein the
current measurements are time aligned using a timestamp.
47. The computer-readable storage medium of claim 44, wherein the
voltage measurements are time aligned using a timestamp.
48. The computer-readable storage medium of claim 44, wherein the
current measurements, the voltage measurements, and the dynamic
topology data are time aligned using one or more timestamps.
49. The computer-readable storage medium of claim 48, wherein the
current measurements and the voltage measurements comprise
synchrophasors.
50. The computer-readable storage medium of claim 49, wherein one
or more of the IEDs comprise an IEEE C37.188 device and wherein the
dynamic topology data, the current measurements, and the voltage
measurements are received by a IEEE C37.118 device.
51. The computer-readable storage medium of claim 50, wherein
determining an operating topology of the electrical power system
comprises: determining a current topology of the electrical power
system comprising a current branch-to-node data array; and merging
nodes according to closed branches without measurements in the
current branch-to-node data array using the static topology of the
electrical power system and the dynamic topology data.
52. The computer-readable storage medium of 51, wherein the current
topology comprises a current correction factor, and wherein the
computer-readable storage medium comprises instructions to
normalize a current measurement using the current correction
factor.
53. The computer-readable storage medium of claim 52, wherein
normalizing a current measurement normalizes the current
measurement relative to one selected from the group consisting of a
turn ratio of a current transformer used to obtain the current
measurement and an orientation of the current measurement in the
current topology.
54. The computer-readable storage medium of claim 51, wherein the
computer-readable storage medium comprises instructions to perform
a current consistency check on a particular branch in the current
branch-to-node data array, the method comprising: determining a
median or mean value of a plurality of current measurements on the
particular branch in the current branch-to-node data array;
calculating a difference between each of the plurality of current
measurements on the particular branch and the median or mean value;
comparing each of the plurality of differences to a user-defined
current consistency threshold; setting a current consistency alarm
on the branch if one or more of the differences exceeds the
user-defined current consistency threshold.
55. The computer-readable storage medium of claim 54, wherein the
current consistency check is performed on each phase of
three-phase, current measurements of the particular branch.
56. The computer-readable storage medium of claim 52, wherein the
computer-readable storage medium comprises instructions to perform
an unbalance check on a particular branch in the current
branch-to-node data array, the method comprising: calculating an
unbalance based on a ratio of a magnitude of a selected phase of a
current measurement on the particular branch to a reference
current; comparing the ratio to a user-defined current unbalance
threshold; and asserting a current unbalance alarm on the selected
phase of the particular current measurement if the unbalance
exceeds the user-defined current unbalance threshold.
57. The computer-readable storage medium of claim 56, wherein the
reference current is a median of a plurality of current
measurements on the particular branch in the current branch-to-node
data array.
58. The computer-readable storage medium of claim 52, wherein the
computer-readable storage medium comprises instructions to perform
a method to check symmetrical components of a selected current
measurement on a particular branch in the branch to node data
array, the method comprising: calculating symmetrical components of
the selected current measurement on the particular branch in the
branch to node data array; comparing the symmetrical components to
user-defined current symmetrical component thresholds; and
asserting symmetrical component alarms on the particular branch if
one or more of the symmetric components exceeds the user-defined
current symmetrical component threshold.
59. The computer-readable storage medium of claim 52, wherein the
current topology comprises a current branch to node data array and
a current merged node data array, wherein the current branch to
node data array includes information concerning interconnection of
the nodes, and wherein the current merged node data array includes
information concerning a number of nodes and node information
within the group.
60. The computer-readable storage medium of claim 59, wherein the
computer-readable storage medium comprises instructions to perform
a Kirchhoff's Current Law (KCL) check on a particular entry in the
current merged node data array, the method comprising: summing the
current measurements on each branch in the branch list of the
particular entry in the current merged node data array; and
asserting a status on the particular entry in the branch list if
the sum does not exceed a user-defined current consistency
threshold.
61. The computer-readable storage medium of claim 60, wherein the
KCL check is performed on each phase of three-phase current
measurements on the particular entry in the current merged node
data array.
62. The computer-readable storage medium of claim 51, wherein the
computer-readable storage medium comprises instructions to refine
the current measurements of the branch list of the particular entry
in the current merged node data array using a error minimization if
the current measurements of the particular entry in the current
merged node data array satisfy the user-defined KCL threshold.
63. The computer-readable storage medium of claim 62, wherein
refinement is obtained by error minimization formed according to
the following equation: I i = A i - j = ? ? j ? , i = , 2 , , n
##EQU00009## ? indicates text missing or illegible when filed
##EQU00009.2##
64. The computer-readable storage medium of claim 62, wherein the
current measurements comprise three-phase, current measurements,
and wherein each phase of the three-phase, current measurements are
refined using the correction matrix.
65. The computer-readable storage medium of claim 48, wherein
determining an operating topology of the electrical power system
comprises determining a voltage topology of the electrical power
system comprising a voltage merged node data array and a voltage
branch-to-node data array, wherein each entry in the voltage
branch-to-node data array comprises one or more nodes.
66. The computer-readable storage medium of claim 5, wherein
computer-readable storage medium comprises instructions to perform
a voltage consistency check on a particular entry in the voltage
merged node data array, the method comprising: calculating a median
voltage of the voltage measurements on each group of nodes in the
particular entry in the voltage merged node data array; determining
a difference between each of the voltage measurements and the
median voltage; and asserting a voltage consistency alarm on the
particular voltage node group if one or more of the differences
exceeds a user-defined voltage consistency threshold.
67. The computer-readable storage medium of claim 66, wherein the
voltage consistency check is performed on each phase of three-phase
voltage measurements of the particular voltage node group.
68. The computer-readable storage medium of claim 65, wherein the
computer readable medium comprises instructions to refine one or
more voltage measurements of a particular entry in the voltage
merged node data array.
69. The computer-readable storage medium of claim 68, wherein
refining a voltage measurement of the particular entry in the
voltage merged node data array group comprises setting the voltage
measurement to the median or mean voltage of the particular entry
in the voltage node group.
70. The computer-readable storage medium of claim 65, wherein the
computer-readable instructions comprise instructions to perform a
method for checking symmetrical components of one or more voltage
measurements on a particular entry in the voltage branch-to-node
data array, the method comprising: calculating symmetrical
components of a voltage measurement of the particular entry in the
voltage branch-to-node data array; and setting a voltage
symmetrical component status on the particular entry in the voltage
branch-to-node data array if one or more of the symmetrical
components do not exceed a user-defined voltage symmetrical
component threshold.
71. The computer-readable storage medium of claim 44, wherein the
computer readable storage medium further comprises instructions to
transmit one or more current measurements and/or voltage
measurements to an external device.
72. The computer-readable storage medium of claim 71, wherein the
computer readable storage medium further comprises instructions to
transmit to an external device one or more alarms generated
responsive to the current measurements and the voltage
measurements.
73. The computer-readable storage medium of claim 43, wherein the
computer readable medium further comprises instructions to transmit
one or more refined current measurements and/or refined voltage
measurements to a user programmable task module, wherein the user
programmable task module is configured to perform one or more user
programmable tasks using the voltage measurements and/or the
current measurements and/or the refined current and/or refined
voltage measurements.
74. A system for monitoring an electrical power system comprising a
plurality of nodes interconnected by one or more branches, the
system comprising: a plurality of intelligent electronic devices
(IEDS) communicatively coupled to the electrical power system to
obtain a plurality of current measurements, a plurality of voltage
measurements, and dynamic topology data therefrom; a communication
module communicatively coupled to the plurality of IEDs to receive
the plurality of current measurements, the plurality of voltage
measurements, and the dynamic topology data therefrom, wherein the
communication module comprises a time alignment module to time
align the plurality of current measurements and the plurality of
voltage measurements; a topology processor communicatively coupled
to the communication module comprising a static topology of the
electrical power system, wherein the topology processor is
configured to determine an operating topology of the electrical
power system using the static topology and the dynamic topology
data received from the plurality of IEDs, and wherein the operating
topology comprises a current topology and a voltage topology; a
current processor communicatively coupled to the topology processor
and the communication module, wherein the current processor is
configured to normalize one or more of the plurality of current
measurements using one or more current correction factors defined
in the current topology, and wherein the current processor is
configured to perform a current consistency check, an unbalance
check, a symmetric components check, and a Kirchhoff's Current Law
(KCL) check on the electrical power system using the current
topology and the plurality of current measurements; a voltage
processor communicatively coupled to the topology processor and the
communication module, wherein the voltage processor is configured
to normalize one or more of the plurality of voltage measurements
using one or more voltage correction factors defined in the voltage
topology, and wherein the voltage processor is configured to
perform a voltage consistency check and a symmetric components
check on the electrical power system using the voltage topology and
the plurality of voltage measurements; and a phase measurement and
control unit (PMCU) communicatively coupled to the current
processor and the voltage processor to transmit one or more
normalized current measurements and/or voltage measurements
produced by the current processor and/or voltage processor, the
current measurements and phase measurements being normalized,
refined, or raw, to an external device, the PMCU further
communicatively coupled to the current processor and the voltage
processor to transmit alarms and outputs to the external
device.
75. A method for monitoring an electrical power system comprising a
plurality of nodes interconnected by one or more branches having a
plurality of intelligent electronic devices (IEDs) communicatively
coupled thereto, the method comprising: storing a static topology
of the electrical power system; receiving from the plurality of
IEDs a plurality of current measurements, a plurality of voltage
measurements, and dynamic topology data, wherein the plurality of
current measurements, the plurality of voltage measurements, and
the dynamic topology data are time aligned using one or more
timestamps; determining an operating topology of the electrical
power system using the static topology data and the dynamic
topology data obtained from the plurality of IEDs, wherein the
operating topology comprises a current topology and a voltage
topology; monitoring the electrical power system using the current
topology and the plurality of current measurements, the monitoring
comprising; normalizing one or more of the plurality of current
measurements using one or more phase current correction factors
defined in the current topology, performing a consistency check on
one or more branches of the electrical power system having a
plurality of current measurements thereon, performing an unbalance
check on one or more of the plurality of current measurements,
performing a symmetrical component check on one or more of the
plurality of current measurements, performing a Kirchhoff's Current
Law (KCL) check on a plurality of current measurements reaching a
common node in the current topology, and refining the plurality of
current measurements reaching the common node in the current
topology using a correction matrix, monitoring the electrical power
system using the voltage topology and the plurality of voltage
measurements, the voltage monitoring comprising; normalizing one or
more of the plurality of voltage measurements using one or more
voltage correction factors defined in the voltage topology,
performing a voltage symmetrical component check on one or more of
the plurality of voltage measurements, and performing a voltage
consistency check on a plurality of voltage measurements of one or
more nodes in the voltage topology, refining the plurality of
voltage measurements of the one or more nodes in the voltage
topology; transmitting one or more of the normalized current
measurements and/or voltage measurements to an external monitoring
system.
76. A method for visualizing a state and topology of an electrical
power system comprising a plurality of nodes interconnected by one
or more branches having a plurality of intelligent electronic
devices (IEDs) communicatively coupled thereto, the method
comprising: storing a static topology of the electrical power
system; receiving from the plurality of IEDs a plurality of current
measurements, a plurality of voltage measurements, and dynamic
topology data; determining an operating topology of the electrical
power system using the static topology and the dynamic topology
data; calculating refined current measurements and refined voltage
measurements from the plurality of current measurements and the
plurality of voltage measurements; and providing for displaying the
operating topology, the refined current measurements, and the
refined voltage measurements on a display of a human machine
interface.
77. The method of claim 76, wherein the current measurements are
time aligned.
78. The method of claim 76, wherein the voltage measurements are
time aligned.
79. The method of claim 76, wherein the current measurements, the
voltage measurements, and the dynamic topology data are time
aligned.
80. The method of claim 79, wherein the current measurements and
the voltage measurements comprise synchrophasors.
81. The method of claim 76, wherein calculating refined current
measurements comprises normalizing one of more of the plurality of
current measurements using a phase current correction factor.
82. The method of claim 76, wherein calculating refined voltage
measurements comprises normalizing one or more of the plurality of
voltage measurements using a phase voltage correction factor.
83. The method of claim 76, further comprising: setting an alarm on
a component of the electrical power system; and providing for
displaying the alarm on the display of the human machine
interface.
84. The method of claim 83, wherein setting an alarm comprises
setting a current consistency alarm on a branch of the electrical
power system.
85. The method of claim 83, wherein setting an alarm comprises
setting a current unbalance alarm on a branch of the electrical
power system.
86. The method of claim 83, wherein setting an alarm comprises
setting a current symmetrical component alarm on a branch of the
electrical power system.
87. The method of claim 83, wherein setting an alarm comprises
setting a Kirchhoff's Current Law alarm on a branch of the
electrical power system.
88. The method of claim 83, wherein setting an alarm comprises
setting a voltage consistency check on a node of the electrical
power system.
89. The method of claim 83, wherein setting an alarm comprises
setting a voltage symmetrical component alarm on a node of the
electrical power system.
90. The method of claim 83, wherein the display of the human
machine interface is selectable, the method further comprising
displaying data related to an alarm responsive to a selection of
the alarm in the display of the human machine interface.
91. A system for visualizing a state and topology of an electrical
power system comprising a plurality of nodes interconnected by one
or more branches, the system comprising: a communication module
communicatively coupled to a plurality of intelligent electronic
devices (IEDs), wherein each IED is communicatively coupled to a
portion of the electrical power system to obtain measurement data
therefrom; a state and topology processor communicatively coupled
to the communication module; and a human machine interface (HMI)
comprising a display communicatively coupled to the state and
topology processor, wherein the state and topology processor is
configured to receive measurement data from the IEDs and to
determine an operating topology of the electrical power system
therefrom, and wherein HMI is configured to display the operating
topology on the display to a user.
92. The system of claim 91, wherein the measurement data received
from the plurality of IEDs comprises a plurality of current
measurements and a plurality voltage measurements.
93. The system of claim 92, wherein the plurality of current
measurements and the plurality of voltage measurements are time
aligned.
94. The system of claim 93, wherein the plurality of current
measurements comprise synchrophasors.
95. The system of claim 93, wherein the state and current processor
is configured to normalize the plurality of time aligned current
measurements and the plurality of time aligned voltage measurements
using respective phase current correction factors and phase voltage
correction factors.
96. The system of claim 93, wherein the HMI is configured to
display one or more of the time aligned current measurements and/or
one or more of the time aligned voltage measurements.
97. The system of claim 96, wherein the one or more time aligned
current measurements and/or the one or more time aligned voltage
measurements are displayed concurrently with the operating
topology.
98. The system of claim 93, wherein the state and current processor
is configured to refine one or more of the plurality of current
measurements, and wherein the HMI is configured to display one or
more of the refined current measurements on the display
concurrently with the operating topology.
99. The system of claim 93, wherein the state and voltage processor
is configured to refine one or more of the plurality of voltage
measurements, and wherein the HMI is configured to display one or
more of the refined voltage measurements concurrently with the
operating topology.
100. The system of claim 93, wherein the state and current
processor is configured to set a current alarm on one or more of
the branches in the electrical power system.
101. The system of claim 100, wherein the HMI is configured to
display the current alarm on the HMI display concurrently with the
operating topology.
102. The system of claim 101, wherein the current alarm is one
selected from the group consisting of a current consistency alarm,
a current unbalance alarm, a current symmetrical component alarm,
and a Kirchhoff's Current Law alarm.
103. The system of claim 93, wherein the state and current
processor is configured to set a voltage alarm on one or more of
the nodes in the electrical power system.
104. The system of claim 103, wherein the HMI is configured to
display the current alarm on the HMI display concurrently with the
operating topology.
105. The system of claim 104, wherein the voltage alarm is one
selected from the group consisting of a voltage consistency alarm
and a voltage symmetrical component alarm.
106. A system for visualizing a state and topology of an electrical
power system comprising a plurality of nodes interconnected by one
or more branches, the system comprising: a communication module
communicatively coupled to a plurality of intelligent electronic
devices (IEDs), wherein each of the plurality of IEDs is
communicatively coupled to a respective portion of the electrical
power system to obtain measurement data therefrom; a state and
topology processor comprising a static topology of the electrical
power system communicatively coupled to the communication module to
receive a plurality of time aligned current measurements, a
plurality of time aligned voltage measurements, and dynamic
topology data therefrom, wherein the state and topology processor
is configured determine an operating topology of the electrical
power system, to refine one or more of the plurality of current
measurements, to refine one or more of the plurality of voltage
measurements, and to set one or more alarms on one or more
components of the electrical power system responsive to receiving
the time aligned current measurements, time aligned voltage
measurements, and dynamic topology data from the plurality of IEDs;
and a human machine interface (HMI) comprising a display
communicatively coupled to the state and topology processor,
wherein the HMI is configured to display the operating topology,
the one or more refined current measurements, the one or more
refined voltage measurements, and the one or more alarms on the
display.
Description
RELATED APPLICATIONS
[0001] This Application claims priority to United States
Provisional Application No. 60/978,711, entitled "Real Time State
and Topology Processor" filed Oct. 9, 2007, which is hereby
incorporated by reference in its entirety.
TECHNICAL FIELD
[0002] This disclosure relates to a device for monitoring and
controlling an electrical power system and, more particularly, to a
device for receiving power system network data, measurement data,
and user-defined thresholds to produce a substation state and
topology output, refined current and voltage measurements, and
alarms.
BRIEF DESCRIPTION OF THE DRAWINGS
[0003] Additional aspects and advantages will be apparent from the
following detailed description of preferred embodiments, which
proceeds with reference to the accompanying drawings, wherein:
[0004] FIG. 1 is a block diagram of one embodiment of a substation
state and topology processor in communication with a substation,
electrical power system network;
[0005] FIG. 2A is a block diagram of an embodiment of a substation,
electrical power system network;
[0006] FIG. 2B depicts an embodiment of branch input data
structure;
[0007] FIG. 2C depicts an embodiment of a node input list data
structure;
[0008] FIG. 3 is a data flow diagram of one embodiment of a
substation state and topology processor;
[0009] FIG. 4 is a block diagram of a substation state and topology
processor;
[0010] FIG. 5 is a block diagram of a state and topology
processor;
[0011] FIG. 6 is a block diagram of a substation, electrical power
system network;
[0012] FIG. 7A is a flow diagram of a method for processing merged
branches in a current branch-to-node data structure;
[0013] FIG. 7B is a flow diagram of a method for processing merged
branches in a voltage branch-to-node data structure;
[0014] FIG. 8A is a flow diagram of one embodiment of a method for
generating a current node vector;
[0015] FIG. 8B is a flow diagram of one embodiment of a method for
generating a voltage node vector;
[0016] FIG. 9 is a block diagram of a current and/or voltage node
vector;
[0017] FIG. 10 is a flow diagram of a method for monitoring a
substation, electrical power system network using a current
topology and a plurality of current measurements;
[0018] FIG. 11 is a block diagram of a polarity convention;
[0019] FIG. 12A is a flow diagram of a method for performing a
current consistency check;
[0020] FIG. 12B is a graphical depiction of a current and/or
voltage consistency check;
[0021] FIG. 13A is a flow diagram of a method for performing a
Kirchhoff's Current Law and current measurement refinement;
[0022] FIG. 13B is a block diagram of a portion of a substation,
electrical power system network;
[0023] FIG. 14 is a flow diagram of a method for performing a phase
current unbalance check and symmetrical components check;
[0024] FIG. 15 is a flow diagram of a method for performing a
voltage consistency check, measurement refinement, and symmetrical
components check;
[0025] FIG. 16 depicts one embodiment of an application for
visualizing a substation power system network; and
[0026] FIG. 17 depicts one embodiment of an application for
visualizing measurement and/or alarm details.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
[0027] The embodiments of the disclosure will be best understood by
reference to the drawings, wherein like elements are designated by
like numerals throughout. In the following description, numerous
specific details are provided for a thorough understanding of the
embodiments described herein. However, those of skill in the art
will recognize that one or more of the specific details may be
omitted or other methods, components, or materials may be used. In
some cases, operations are not shown or described in detail.
[0028] Furthermore, the described features, operations, or
characteristics may be combined in any suitable manner in one or
more embodiments. It will also be readily understood that the order
of the steps or actions of the methods described in connection with
the embodiments disclosed may be changed as would be apparent to
those skilled in the art. Thus, any order in the drawings or
Detailed Description is for illustrative purposes only and is not
meant to imply a required order, unless specified to require an
order.
[0029] Embodiments may include various steps, which may be embodied
in machine-executable instructions to be executed by a
general-purpose or special-purpose computer (or other electronic
device). Alternatively, the steps may be performed by hardware
components that include specific logic for performing the steps or
by a combination of hardware, software, and/or firmware.
[0030] Embodiments may also be provided as a computer program
product, including a computer-readable storage medium having stored
thereon instructions that may be used to program a computer (or
other electronic device) to perform processes described herein. The
computer-readable storage medium may include, but is not limited
to: hard drives, floppy diskettes, optical disks, CD-ROMs,
DVD-ROMs, ROMs, RAMs, EPROMs, EEPROMs, magnetic or optical cards,
solid-state memory devices, or other types of
media/machine-readable medium suitable for storing electronic
instructions.
[0031] Several aspects of the embodiments described will be
illustrated as software modules or components. As used herein, a
software module or component may include any type of computer
instruction or computer executable code located within a memory
device and/or transmitted as electronic signals over a system bus
or wired or wireless network. A software module may, for instance,
comprise one or more physical or logical blocks of computer
instructions, which may be organized as a routine, program, object,
component, data structure, etc., that performs one or more tasks or
implements particular abstract data types.
[0032] In certain embodiments, a particular software module may
comprise disparate instructions stored in different locations of a
memory device, which together implement the described functionality
of the module. Indeed, a module may comprise a single instruction
or many instructions, and may be distributed over several different
code segments, among different programs, and across several memory
devices. Some embodiments may be practiced in a distributed
computing environment where tasks are performed by a remote
processing device linked through a communications network. In a
distributed computing environment, software modules may be located
in local and/or remote memory storage devices. In addition, data
being tied or rendered together in a database record may be
resident in the same memory device or across several memory
devices, and may be linked together in fields of a record in a
database across a network.
[0033] FIG. 1 depicts an exemplary substation, electrical power
system network (SEPSN) 100. The SEPSN 100 may comprise various
elements used for electrical power transmission and/or power
distribution. For example, the SEPSN 100 may comprise a generator
110, which may be connected to a bus 120 via a circuit breaker 113.
A load 117 may be connected to the bus 120 via a circuit breaker
115. As used herein, a circuit breaker (such as circuit breakers
113 and 115) may refer to any device capable of interrupting and/or
altering an electric circuit and/or an electrical connection (such
as a connection between generator 110 and load 117).
[0034] A bus 130 may be connected to bus 120 via power transmission
line 132. A power transmission line 132 may comprise circuit
breakers 133 and 135. A bus 140 may be connected to the bus 120 via
a power transmission line 142. The power transmission line 142 may
comprise circuit breakers 143, and 147.
[0035] One or more Intelligent Electronic Devices (IED) 150, 152,
and 154 may be communicatively coupled to one or more elements of
the SEPSN 100. As used herein, an IED may refer to any one or
combination of a central processing unit (CPU)-based relay and/or
protective relay, communication processor, digital fault recorder,
phasor measurement unit (PMU), phasor measurement and control unit
(PMCU), phasor data concentrator (PDC), wide area control system
(WACS), relays with phasor measurement capabilities, wide area
protection system (WAPS), a Supervisory Control and Data
Acquisition (SCADA) systems, system integrity protection schemes,
or any other device capable of monitoring an electrical power
system.
[0036] In the FIG. 1 embodiment, a PMU 150 may be configured to
measure or otherwise sample a signal (e.g., a phase current and/or
phase voltage waveform) on bus 120. The waveform may comprise a
voltage and/or current waveform corresponding to one or more
components of a three-phase signal; Similarly, PMU 152 may be
configured to sample a signal waveform present on bus 130, and PMU
154 may be configured to sample a signal waveform present on bus
140.
[0037] The PMUs 150, 152, and 154 may be configured to process
sampled signal waveforms to calculate, for example, current and/or
voltage phasors. The PMUs 150, 152, and. 154 may read one or more
correction factors (that may be input by the user) for modifying
the magnitude and/or phase of a phasor measurement. As used herein,
"measurement data" may refer to a phasor measurement of a
sinusoidal signal. In some embodiments, measurement data may refer
to a measurement of a three-phase, phase current and/or voltage
signal (e.g., a measurement may comprise three separate
measurements of each phase of a three-phase signal).
[0038] The PMUs 150, 152, and 154 may be configured to apply a
timestamp to data. This may be done using any phasor measurement
and/or timestamping technique and/or methodology known in the art,
including, but not limited to the techniques and methods described
in: U.S. Pat. No. 6,662,124 entitled, "Protective Relay with
Synchronized Phasor Measurement Capability for Use in Electric
Power Systems," to Schweitzer, III et al.; U.S. Pat. No. 6,845,333
entitled, "Protective Relay with Synchronized Phasor Measurement
Capability for Use in Electric Power Systems," to Anderson et al.;
and U.S. Application Pub. No. 2007/0086134 entitled, "Apparatus and
Method for Estimating Synchronized Phasors at Predetermined Times
Referenced to an Absolute Time Standard in an Electrical System" to
Zweigle et al., each of which is hereby incorporated by reference
in its entirety.
[0039] The measurement data obtained by the PMUs 150, 152, and 154
may be communicated to a Data Processor (DP) 160. In addition, one
or more of the PMUs 150, 152, and 154 may communicate dynamic
topology data to the DP 160. This dynamic topology data may
comprise the state of the circuit breakers and/or switches 113,
115, 133, 135, 143, 147 of the SEPSN 100, and the like. As will be
discussed in additional detail below, dynamic topology data may be
combined with static network topology data to generate an operating
topology of the SEPSN. The static topology data may comprise
information, such as: the number of nodes in the SEPSN 100, the
connection between various nodes in the SEPSN 100 the measurements
available for each node and/or branch in the SEPSN 100, phase
current and/or voltage measurement correction factors, and the
like.
[0040] As used herein, a "node" may refer to a bus, such as buses
120, 130, and 140 of the SEPSN 100, and a "branch," as used herein,
may refer to a path of conduction and/or connection between one or
more nodes (e.g., a power transmission line comprising zero or more
circuit breakers or the like).
[0041] Elements 150, 152, and 154 may comprise IEDs, such as PMUs
and/or PMCUs, which may be configured to gather measurement data
and dynamic topology data for transmission to DP 160. This data may
comprise, but is not limited to: one or more phase current
measurements on a branch and/or voltage measurements on a node 120,
130, and/or 140; the status of circuit breakers and/or disconnect
switches 113, 115, 133, 135, 143, 147; the quality status of these
circuit breakers and/or disconnect switches; and the like.
[0042] The DP 160 may comprise configuration data including one or
more user-defined thresholds. These user-defined thresholds may be
used in one or more monitoring functions of the DP 160. For
example, the DP 160 may receive phase measurements and dynamic
topology data from PMUs 150, 152, and 154. The DP 160 may use this
data to evaluate and/or monitor the state of the SEPSN 100. This
monitoring may comprise comparing the received measurement and
network topology data to the user-defined thresholds. The DP 160
may process the measurements received from the PMUs 150, 152, and
154 and may set one or more alarms responsive to the processing. As
will be discussed below, such alarms may include, but are not
limited to: current and/or voltage consistency alarms; current
and/or voltage unbalance alarms; current and/or voltage symmetrical
component alarms; and the like.
[0043] FIG. 2A depicts an embodiment of a SEPSN 200 (e.g.,
substation, electrical power system network). The SEPSN 200 may
comprise ten (10) nodes denoted N1 through N10. The SEPSN 200 may
further comprise thirteen (13) branches denoted B1 through B13.
[0044] The SEPSN 200 may comprise one or more IEDs (elements
IED1-IED5) communicatively coupled thereto. IED1 may be
communicatively coupled to current transformers (CTs) CT1 and CT2.
In this embodiment, IED1 may comprise a PMU and/or PMCU or a relay.
CTs 1 and 2 may be used to obtain current measurements on branches
in the SEPSN 200. Although not shown in FIG. 2A, one or more
voltage transformers may be used to obtain phase voltage
measurements on one or more of the nodes (N1-N10) of the SEPSN 200.
The CT1 may measure a current between N1 and N4, and CT 2 may
measure a current from N3 to N4, and so on. The IEDs coupled to the
SEPSN 200 may be in communication with branch elements of the SEPSN
200. For example, IED2 may be communicatively coupled to branch B1
and B2, and may be configured to detect the state of branch B1 and
B2 (e.g., whether the branches B1 and/or B2 are closed, and the
like).
[0045] As depicted in FIG. 2A, the SEPSN 200 may comprise a
plurality of IEDs1-5 monitoring one more aspects of the SEPSN 200,
including topology data of the SEPSN 200 (e.g., the state of
branches B1-B11) and/or measurement data (e.g., phase current
measurements obtained by current transformers CT1-CT8). The data
collected by the IEDs 1-5 may be transmitted to a state and
topology processor (not shown) and made available to various
protective and monitoring functions running thereon in one or more
data structures. Various embodiments of such data structures are
described below in conjunction with FIGS. 2B and 2C.
[0046] In one embodiment, two data structures may be used to
describe the SEPSN 200, a branch input list data structure (shown
in FIG. 2B) and a node input list data structure (shown in FIG.
2C).
[0047] The branch input list data structure may comprise
information about a branch in a SEPSN (e.g., branches B1-B11 in
FIG. 2A). The branch input list data structure may comprise an
entry for each branch in the network, and each entry may comprise
data describing the branch. As such, the branch input list data
structure may comprise: [0048] 1) The number of branches in the
SEPSN (e.g., 11 branches in FIG. 2A) [0049] 2) A branch input data
structure for each branch, comprising: [0050] a) A FROM node
identifier; [0051] b) A TO node identifier; [0052] c) Branch Closed
Status (whether the branch is closed) [0053] d) Branch Close Status
Quality (whether the branch close status is good) [0054] e) Number
of current measurements on the branch [0055] f) A-Phase
measurements [0056] i) Current measurements [0057] ii) Current
correction factors [0058] g) B-Phase measurements [0059] i) Current
measurements [0060] ii) Current correction factors [0061] h)
C-Phase measurements [0062] i) Current measurements [0063] ii)
Current correction factors [0064] i) Threshold data [0065] i)
Current consistency threshold [0066] ii) Current unbalance
threshold [0067] iii) Positive, negative, and zero sequence
overcurrent threshold [0068] iv) KCL threshold
[0069] FIG. 2B depicts one embodiment 210 of data structure 220,
comprising a branch input list data structure 230 corresponding to
the SEPSN 200 of FIG. 2A. Although FIGS. 2B and 2C depict tree data
structures 210, one skilled in the art would recognize that any
data organization technique and/or methodology known in the art
could be used under the teachings of this disclosure, and as such,
this disclosure should not be read as limited to any particular
data structure type.
[0070] A top-level node 220 of the tree data structure 210 may be
labeled INPUT_DATA. The INPUT_DATA node 220 may be configured to
contain a branch list 230, which comprises one or more branch input
list data structures 240 described above. Additionally, the
INPUT_DATA node 220 may comprise a "list_of_nodes" entry (not
shown), which will be described in detail below in conjunction with
FIG. 2C.
[0071] The "list_of_branches" entry 230 may comprise a
"number_of_branches" entry 232 indicating the number of branches in
the SEPSN (e.g., in the SEPSN 200 depicted in FIG. 2A, the
"number_of_branches=11") and one or more branch input list
instances 240. Each node of the SEPSN 200 depicted in FIG. 2A may
have a corresponding branch instance 240 (e.g., a branch input list
instance 240 for each of the eleven (11) branches in substation
network 200).
[0072] Branch three (3) (B3 in FIG. 2A) may be described by branch
instance 250. Branch instance 250 may comprise one or more child
instances defining the branch configuration, the branch state,
phase-current measurements on the branch, phase-current correction
factors, and one or more user-defined threshold values. For
example, a "from_node" 251 may identify the source node of the
branch (and a "to_node" 252 may identify a destination node of the
branch to accurately reflect the topology of the SEPSN 200;
referring back to FIG. 2A, branch 3 (B3) is coupled to nodes N4 and
N3.
[0073] Referring again to FIG. 2B, the "closed" instance 254 and
the "closed_status_quality" instance 255 may indicate that branch
(B3) is closed and that the closed quality status is good.
[0074] The "number_of_current_measurements" instance 256 may
indicate the number of measurements available on the branch (e.g.,
two (2) measurements for branch B3). Referring again to FIG. 2A,
branch B3 comprises two CTs (CT2 and CT3) communicatively coupled
thereto.
[0075] The "branch" instance 250 may comprise one or more
phase-current measurements and phase-current correction factors
260, 270, and 280 associated with the branch 250. An "A_phase"
instance 260 may comprise the A phase current measurements and
correction factors of the branch 250. A "B_phase" instance 270 may
comprise the B phase current measurements and correction factors of
branch 3 250. And a "C_phase" instance 280 may comprise the C phase
current measurements and correction factors of branch three (3)
250.
[0076] Each phase measurement/correction factor instance 260, 270,
and 280 may comprise a current measurement instance (e.g., instance
261) and a correction factor instance (e.g., instance 263) for each
current measurement on the branch. For example, in FIG. 2B,
instance 256 indicates that branch 3 250 comprises two (2) current
measurements. As such, the A_phase current measurement instance 261
may comprise two (2) A phase current measurements instances 261.1
and 261.2 under instance 261 and two (2) A phase current correction
factors 263.1 and 263.2 under current correction factor instance
263.
[0077] A "current_measurement" instance 261.1 may comprise a
measured current magnitude measurement 261.1A, and a
"current_phase_measurement" instance 261.1.B may comprise a
corresponding phase measurement. The current measurement instance
261.2 may comprise similar measurements (not shown).
[0078] The "current_correction_factor" instance 263 may comprise a
first current correction factor 263.1 associated with the first
current measurement instance 261.1. The
"current_correction_factor[1]" instance 263 may comprise child
instances 263.1A and 263.1 B defining a magnitude correction factor
263.1A and a phase-angle correction factor 263.1B. The use of
correction factors 263.1 and 263.2 are discussed in more detail
below. The "current_correction_factor[2]" instance 263.2 may
comprise current correction factors for current measurement 2,
261.2.
[0079] The B_phase instance 270 and the C_phase instance 280 may
each comprise one or more current measurements (not shown) and
current correction factors (not shown) for the B and C phases of a
three-phase current, respectively.
[0080] The branch instance 250 may comprise one or more user
defined constants 257. As discussed above, a branch constant 257
may comprise a current consistency threshold 257.1, a current
unbalance threshold 257.2, and a positive, negative, and zero
sequence overcurrent threshold. The use of constants 257 is
described in more detail below.
[0081] The "INPUT_DATA" instance 210 may further comprise a
"node_input_list" (not shown in FIG. 2B), which may comprise data
describing one or more nodes in a SEPSN (e.g., substation,
electrical power system network 200 of FIG. 2A). As such, the
"node_input_list" entry may comprise a sub-entry for each node in
the network, and each sub-entry therein may comprise data
describing the node and any phase voltage measurements thereon. In
one embodiment, a node input list structure may comprise: [0082] 1)
Number of nodes in the SEPSN (e.g., 10) [0083] 2) A node_input_data
structure for each node, comprising: [0084] a) KCL node information
[0085] b) A-Phase measurements at the node [0086] i) Number of
voltage measurements [0087] ii) Voltage measurements [0088] iii)
Voltage correction factors [0089] c) B-Phase measurements at the
node [0090] i) Number of voltage measurements [0091] ii) Voltage
measurements [0092] iii) Voltage correction factors [0093] d)
C-Phase measurements at the node [0094] i) Number of voltage
measurements [0095] ii) Voltage measurements [0096] iii) Voltage
correction factors [0097] e) Positive-sequence undervoltage
threshold [0098] f) Negative-sequence overvoltage threshold [0099]
g) Zero-sequence overvoltage threshold
[0100] FIG. 2C depicts one embodiment of a data structure 210
comprising a "node_list" instance 235. As discussed above, the
"INPUT_DATA" instance 220 may comprise a "list_of_branches"
instance 230 containing data describing one or more branches in a
SEPSN. The "INPUT_DATA" node 220 may further comprise a
"list_of_nodes" instance 235, which may comprise a
"number_of_nodes" instance 247, indicating the number of nodes in
the SEPSN. A container instance 249 may comprise a data structure
corresponding to each node in the SEPSN. For example, in the SEPSN
of FIG. 2A, the container instance 249 may comprise ten (10)
instances 265, one for each node in the network 200.
[0101] A node instance 265 may comprise a KCL instance 271, which
may indicate whether the node is suitable for KCL check. As will be
discussed below, a node may be suitable for KCL check if all of the
branches reaching the node are accounted for in the substation
model. In addition, as will be discussed below, a KCL check may be
possible where all the nodes in a particular node group are KCL
nodes, and all the branches leaving the group of nodes are
metered.
[0102] The node instance 265 may further comprise an "A_phase"
instance 273 comprising a "number_of_voltage_measurements" instance
274 and a voltage measurement instance 275. The voltage measurement
instance 275 may comprise one or more A phase voltage measurement
instances 275.1. The "voltage_measurement" instance 275.1 may
comprise an A phase magnitude 275.1A and A phase 275.1B. Although
not shown in FIG. 2C, a B_phase instance 283 and a C_phase instance
293 may comprise similar voltage measurement nodes.
[0103] A_phase instance 275 may further comprise a
"voltage_correction_factor" instance 277, which may comprise one or
more correction factor instances 277.1. The correction factor
instance 277.1 may comprise magnitude 277.1A and phase 277.1B
correction factors associated with the voltage measurement 275.1.
The use of correction factors 275.1 is described in more detail
below. Although not shown in FIG. 2C, the B_phase instance 283 and
the C_phase instance 293 may comprise similar voltage correction
factors.
[0104] The "node[1]" instance 265 may comprise one or more
user-defined thresholds 295. As discussed above, the user-defined
thresholds 295 may comprise a positive-sequence undervoltage
threshold, a negative-sequence overvoltage threshold, and/or a
zero-sequence overvoltage threshold. The use of the user-defined
thresholds 295 is discussed in more detail below.
[0105] FIG. 3 depicts a data flow diagram 300 of one embodiment of
a Substation State and Topology Processor (STP) 360. As shown in
FIG. 3, the STP 360 may receive a static topology input 354, a
dynamic topology data input 355, and measurement data input 356. In
response to these inputs, the STP 360 may output refined
measurements 361 and alarms 362. The dynamic topology data may
include data such as breaker status, disconnect status, and the
like.
[0106] As described above in conjunction with FIGS. 2A-2C, the
static topology data 354 may comprise a data structure, such as
input list data structure 210 of FIGS. 2B and 2C, describing a
topology of a SEPSN. The static topology may be input into the STP
360 from an external storage location. Alternatively, the STP may
comprise data storage means (e.g., memory, disk, or the like) for
storing the static topology data 354. The static topology data 354
may comprise data describing: the nodes in the SEPSN; the branches
in the SEPSN; the number of phase current and/or phase voltage
measurements available on each node and/or branch; phase voltage
and/or current measurement correction factors; and the like.
[0107] The STP 360 may receive dynamic topology data 355. The
dynamic topology data 355 may comprise data relating to the status
of one or more circuit breakers, switches, conductors, conduits, or
the like in a SEPSN. As discussed above, the dynamic topology data
355 may be obtained by one or more IEDs and/or PMUs (not shown)
communicatively coupled one or more components of the SEPSN. As
dynamic topology data 355 is received by the STP 360, the dynamic
topology may be used along with the static topology 354 to
determine an operating topology of the SEPSN. The operating
topology may be embodied as a data structure, such as the tree data
structured discussed above in conjunction with FIGS. 2B and 2C. For
example, dynamic topology data 355 may comprise data relating to
the state of closed branches 254 and/or closed_status_quality node
255 in FIG. 2B.
[0108] STP 360 may receive measurement data 356. Measurement data
356 may comprise one or more phase current and/or phase voltage
measurements obtained by one or more IEDs, PMUs and/or PMCUs (now
shown) communicatively coupled to the SEPSN. As discussed above,
the phase voltage and/or current measurements 356 (as well as the
dynamic topology data 355) may comprise timestamp information to
allow the STP 360 to time align the measurements to a common time
standard.
[0109] Upon receiving inputs 354, 355, and 356, the STP 360 may be
configured to produce one or more normalized and/or refined phase
current and/or phase voltage measurements 361. These refined
measurements may be used in protective and/or monitoring functions
of the SEPSN (not shown). In addition, STP 360 may produce one or
more alarms 362. The alarms 362 may be produced if one or more
measurements 354, 355, 356, and/or derivatives thereof exceed or
otherwise fall outside of one or more user-defined operating
thresholds of STP 360 (e.g., thresholds 257 of FIG. 2B and/or
thresholds 295 of FIG. 2C).
[0110] Turning now to FIG. 4, a block diagram 400 of one embodiment
of a Data Processor (DP) 420 is depicted. DP 420 may be
communicatively coupled to one or more IEDs, such as relays, phasor
measurement and control units (PMCU) and/or phasor measurement
units (PMU) 401 or relays and 416 disposed in and/or
communicatively coupled to a SEPSN. In FIG. 4, The DP 420 is
depicted as communicatively coupled to sixteen (16) PMCUs labeled
PMCU_401-PMCU_416. The PMCU_401-416 may be configured to
communicate with the DP 420 using a communication standard, such as
the IEEE C37.118 standard (hereafter "118 standard"). The 118
standard is a standard for synchronized phasor measurement systems
in power systems. The 118 standard is not media dependent and, as
such, may be used on EIA-232 and Ethernet communications
connections. Accordingly, PMCU_401-416 and DP 420 may be referred
to as "118 devices" configured to interact with the PMCU_401-416
using the 118 standard. One skilled in the art, however, would
recognize that the PMCU_401-416 and the DP 420 could be configured
to use any communications standard and/or protocol known in the
art. As such, this disclosure should not be read as limited to any
particular communications standard and/or protocol. For instance,
in some embodiments, the PMUs 410 through 416 may be
communicatively coupled to the DP 420 via Fast Message protocol or
the like.
[0111] The PMCU_401-416 may provide measurement data and/or network
topology data to the DP 420. This data may comprise timestamp
information according to the 118 standard, or some other time
alignment technique. The messages transmitted by the PCMU_401-416
may comprise time stamping information (e.g., may comprise
synchrophasors transmitted according to the 118 standard). The time
alignment module 430 may time align such messages using the time
stamping information.
[0112] Alternatively, in some embodiments, the time alignment
module 430 may time align messages from the PMCU_401-416 to a
common time reference (not shown), which may provide a common time
reference to the DP 420, the PMCU_401-16 communicatively thereto,
and/or to other IEDs communicatively coupled to the DP 420. The
common time reference (not shown) may be provided by various time
sources including, but not limited to: a Global Positioning System
(GPS); a radio time source, such as the short-wave WWV transmitter
operated by the National Institute of Standards and Technology
(NIST) at 2.5 MHz, 5 MHz, 10 MHz, 15 MHz, and 20 MHz, or a low
frequency transmitter, such as WWVB operated by NIST at 60 Hz; a
cesium clock; an atomic clock; and the like. The time alignment
module 430 may modify the magnitude and/or phase of phase
measurements received from the PMCU_401-416 to conform to the
common time reference (not shown) and/or the PMCU_401-416 may be
configured to modify one or more of a magnitude and/or phase
measurement to align the measurement to the common time reference
(not shown). In addition, in some embodiments, the time alignment
module 430 may comprise a buffer memory or other buffering means to
time align incoming messages from the PMCU_401-416. However, as
discussed above, in the FIG. 4 embodiment, a time reference (not
shown) may not be required since the messages themselves may
comprise time alignment information (e.g., the messages transmitted
by the PMCU_401-416 may comprise synchrophasors or the like).
[0113] A super packet maker module 440 may receive the time-aligned
measurement and dynamic topology data from time alignment module
430, and may generate a single composite packet comprising the
time-aligned data received from the PMCU_401-416. The super packet
maker 440 may be configured to communicate with the time alignment
module using the 118 standard.
[0114] The super packet maker 440 may transmit the packet
comprising the time-aligned phasor measurement and/or topology data
to Run Time System (RTS) 450. In one embodiment, the super packet
maker module 440 may transmit the composite packet RTS 450 using
the 118 standard. In this embodiment, the RTS 450 may comprise a
118 protocol gateway module 452, which may be configured to
communicate with the super packet maker module 440 using the 118
protocol. In other embodiments, other protocols and/or
communications infrastructures may be used in place of the 118
protocol, including, but not limited to: the IEEE 1344 standard;
BPA PDCStream; IEC 61850; OPC-DA/OPC-HAD; Internet Protocol (IP);
Transmission Control Protocol (TCP); TPC/IP; User Datagram Protocol
(UDP); or the like. As such, this disclosure should not be read as
limited to any particular communication protocol, communication
standard, and/or communication infrastructure.
[0115] The RTS 450 may make the time-aligned phase current and/or
phase voltage measurements and dynamic topology data received from
the PMCUs01-16 401-416 available to a state and topology processor
(STP) 460. In addition, the RTS 450 may comprise a data storage
module 454, which may be used to store static network topology
information relating to the SEPSN monitored by the system and/or
the PMCU_401-416. The STP 460 may be communicatively coupled to a
data storage module 454, and may be configured to load network
topology data therefrom. The network topology data stored in the
data storage module 454 may comprise a data structure, such as an
input list data structure depicted in FIGS. 2B and 2C (e.g., input
list data structure 210), and may include a static topology of the
monitored SEPSN. In this embodiment, the STP 460 may be configured
to load the data structure from storage module 454, and to then
update the structure with the phase-current and/or voltage
measurements and dynamic topology data (e.g., status of circuit
breakers, switches, and the like) received from the PMCUs01-16.
[0116] The STP 460 may access the static and dynamic topology data
to refine the received measurements and to perform one or more
protective functions and/or system checks. The operation of the STP
460 is described in more detail below.
[0117] A human-machine interface (HMI) module 470 may be
communicatively coupled to the DP 420 and the STP 460. The HMI
module 470 may be configured to display or otherwise make available
to a human operator the refined current measurements, the refined
phase voltage measurements, and/or alarms (if any) produced by the
STP 460. Accordingly, the HMI module 470 may comprise a user
interface or other display means to display of the state of the
electrical power system to a user.
[0118] A local PMCU 480 may be communicatively coupled to the STP
460 and may be configured to receive the refined measurements
and/or alarms (if any) produced by the STP 460. The local PMCU 480
may be communicatively coupled (via a communications network
supporting, for example, the 118 standard or some other protocol)
to an external device 485. The external device 485 may be an IED or
other device configured to communicate with the PMCU 480. The
external device 485 may be capable of configuring and/or
controlling one or more components of the SEPSN (e.g., open and/or
close one or more circuit breakers and/or switches, remove and/or
add one or more loads or the like). Responsive to the refined
measurements and/or alarms generated by the STP 460, the local PMCU
480 may cause the device 485 to reconfigure and/or control the
SEPSN to thereby provide protection and/or additional control
services to the SEPSN. For example, the external device 485 may be
configured to send an alarm indicating undesired operating
conditions, cause a circuit breaker to open and/or close, a load to
be shed, or the like.
[0119] As discussed above, the STP 460 outputs station topology,
refined measurements, measurement alarms, unbalanced currents and
sequence quantities to the Run Time System 450, including the local
PMCU 480 and a user programmable task module 490. The user
programmable task module 490 may comprise one or more
pre-configured and/or user programmable tasks. As such, the user
programmable task module 490 may comprise an IEC 61131-3 compliant
device (e.g., a programmable device that complies with the IEC
61131-3 standard). The tasks implemented on the user programmable
task module 490 may use the data produced by the STP 460 to monitor
the power system. For example, a bus differential protection module
(not shown) may be implemented on the user programmable task module
490.
[0120] FIG. 5 is a block diagram of one embodiment of a state and
topology Processor (STP) 560. The STP may receive inputs 562 from a
run time engine, such as the Run Time System 450 discussed
above.
[0121] The STP 560 may comprise a topology processor 570, which may
receive branch input data 572. The branch input data 572 may be
derived from the static and dynamic topology data discussed above.
As such, the branch input data 572 may reflect a state of a SEPSN,
and as such, may comprise a combination of static SEPSN
configuration data and dynamic SEPSN data. As used herein, the
combination of static and dynamic topology data generated by the
topology processor 570 may be referred to as an "operating
topology" of a SEPSN.
[0122] The topology processor 570 may use branch input data 572 to
generate a current topology 582 and a voltage topology 592.
Jointly, the current topology 582 and the voltage topology 592 may
comprise an operating topology of the SEPSN. The current topology
582 feeds a current processor 580 and the voltage topology 592
feeds a voltage processor 590.
[0123] The topology processor 570 may merge network nodes to create
node groups according to the closed status of the branches within
topology data 572. To create the current topology 582, the topology
processor 570 may merge nodes when the non-metered branches are
closed or when the branch closed status quality of the branch is
false. To create the voltage topology 592, topology processor 570
may merge nodes when branches are closed. A more detailed
description of current topology 582 and voltage topology 592 are
provided below.
[0124] The current processor 580 may receive the current topology
582, node data 573, and current measurements 584 and produce
outputs 585, which may comprise refined current measurements 585.1,
current unbalance conditions 585.3, and sequence currents 585.4. In
addition, current processor 580 may provide user-defined alarms
585.2 for current unbalance and symmetrical component conditions.
Systems and methods for generating outputs 585 are described in
additional detail below.
[0125] The voltage processor 590 may receive the voltage topology
592, node data 573, and voltage measurements 594 and produce
outputs 595, which may comprise refined voltage measurements 595.1
and sequence voltages 595.3. In addition, the voltage processor 590
may provide user-defined alarms 595.2 for voltage symmetrical
component conditions, measurement consistency. Systems and methods
for generating outputs 595 are provided below.
[0126] As discussed above, the topology processor 570 may use
branch input data 572 (comprising the static topology and the
dynamic topology data) to generate an operating topology of the
SEPSN comprising a current topology 582 and a voltage topology
592.
[0127] The current topology may comprise the list of groups of
nodes and the branch to node list. The nodes inside every group of
nodes are connected by closed branches that have no current
measurements. The branches to node list may specify which metered
closed branches connect which group of nodes.
[0128] The voltage topology may comprise a list of groups of nodes
and a branches to node list. The nodes inside every group of nodes
are connected by closed branches (with or without current
measurements). The branches to node list may specify which open
branches with closed status quality equal to false connect which
groups of nodes.
[0129] Turning now to FIG. 6, an exemplary SEPSN 600 is depicted to
illustrate one embodiment of a node merging process. The network
600 may comprise eleven (11) nodes (denoted N6.1 through N6.11),
seven terminal nodes (N6.5-N6.11) (where KCL=FALSE), eight metered
branches (BR6.1 through BR6.8) as such, branches BR6.1 through
BR6.9 may comprise a current transformer, and three (3) non-metered
branches (BR6.9 through BR6.11). Nodes N6.1, N6.2, N6.3 and N6.4
may comprise a voltage transformer (respectively VT6.1, VT6.2,
VT6.3, and VT6.4) attached and/or communicatively coupled thereto
to measure a voltage on Nodes N6.1 through N6.4.
[0130] When all merging switches of FIG. 6 are open (e.g., branches
BR6.9-11 are open as shown in FIG. 9), the current processor
branch-to-node data may be represented by table 1 below:
TABLE-US-00001 TABLE 1 BR6.1 BR6.2 BR6.3 BR6.4 BR6.5 BR6.6 BR6.7
BR6.8 BR6.9 BR6.10 BR6.11 From N6.1 N6.1 N6.2 N6.2 N6.2 N6.3 N6.4
N6.4 N6.1 N6.1 N6.3 Node ID To N6.5 N6.3 N6.6 N6.7 N6.8 N6.9 N6.10
N6.11 N6.3 N6.2 N6.4 Node ID
[0131] Nodes in the current topology branch-to-node data may be
merged when a non-metered branch is closed or when the branch close
status quality of the non-metered branch is FALSE. After a
non-metered branch closes (or its close status quality is FALSE),
the topology processor may replace all instances of the non-metered
branch TO node identifier with the FROM node identifier in the
branch-to-node data array. The TO node identifier and FROM node
identifier may be defined in a structure, such as data structure
210, discussed above in conjunction with FIG. 2B.
[0132] In the FIG. 6 example, the dynamic topology data 572
associated with the SEPSN 600 may indicate that branch 10 (BR6.10)
has closed. Referring back to FIG. 2B, this may be indicated in the
input data 210 structure as setting element 254 to TRUE and/or
element 255 close status quality indicator to FALSE for the branch.
Closing branch BR6.10 may merge nodes N6.1 and N6.2. As such, the
branch-to-node data of Table 1 may be updated as shown in Table 2,
such that the TO node ID of the merged branch (BR6.2) is replaced
by the FROM node ID of the merged branch:
TABLE-US-00002 TABLE 2 BR6.1 BR6.2 BR6.3 BR6.4 BR6.5 BR6.6 BR6.7
BR6.8 BR6.9 BR6.10 BR6.11 From N6.1 N6.1 N6.1 N6.1 N6.1 N6.3 N6.4
N6.4 N6.1 N6.1 N6.3 Node ID To N6.5 N6.3 N6.6 N6.7 N6.8 N6.9 N6.10
N6.11 N6.3 N6.1 N6.4 Node ID
[0133] As shown in Table 2, the FROM node ID of BR6.3-BR6.5 has
been changed from N6.2 to N6.1 and the TO node ID of BR6.10 has
been changed from N6.2 to N6.1.
[0134] Using the branch-to-node data, the topology processor 570
may generate groups of nodes for consistency checks and/or current
refinement. Table 3 may represent a group of nodes and branch list
generated from Table 2 for current topology 582:
TABLE-US-00003 TABLE 3 Group of Nodes for Current Topology Branch
List N6.1, N6.2 BR6.1, BR6.2, BR6.3, BR6.4, BR6.5 N6.3 BR6.2, BR6
N6.4 BR6.7, BR6.8
[0135] In Table 3, BR6.10 is omitted since the FROM node and TO
node of BR6.10 are the same (see table 2).
[0136] Like the current topology branch-to-node data, the voltage
topology branch-to-node data may comprise branch to node
interconnection information. As discussed above, this information
may be determined by evaluating static and dynamic topology data.
For the purposes of the voltage topology branch-to-node data, the
topology processor 570 may merge a branch if the branch status is
closed (e.g., element 254 of FIG. 2B) and the close status quality
indicator is TRUE for the branch (e.g., element 255 of FIG.
2B).
[0137] A voltage branch-to-node data for the SEPSN 600, before
closing branch BR6.2, is provided in Table 4:
TABLE-US-00004 TABLE 4 BR6.1 BR6.2 BR6.3 BR6.4 BR6.5 BR6.6 BR6.7
BR6.8 BR6.9 BR6.10 BR6.11 From N6.1 N6.1 N6.2 N6.2 N6.2 N6.3 N6.4
N6.4 N6.1 N6.1 N6.3 To N6.5 N6.3 N6.6 N6.7 N6.8 N6.9 N6.10 N6.11
N6.3 N6.2 N6.4
[0138] After closing Branch BR6.2, the topology processor may merge
nodes N6.1 and N6.3, and all instances of the branch TO node may be
replaced with the FROM node ID in the voltage branch-to-node data
array. This change is reflected in the updated voltage
branch-to-node data of Table 5:
TABLE-US-00005 TABLE 5 BR6.1 BR6.2 BR6.3 BR6.4 BR6.5 BR6.6 BR6.7
BR6.8 BR6.9 BR6.10 BR6.11 From N6.1 N6.1 N6.2 N6.2 N6.2 N6.1 N6.4
N6.4 N6.1 N6.1 N6.1 To N6.5 N6.1 N6.6 N6.7 N6.8 N6.9 N6.10 N6.11
N6.1 N6.2 N6.4
[0139] In Table 5, all references to node 3 (N6.3) have been
replaced with the merged node 1 (N6.1), including the TO node IDs
in branches 2 and 9 (BR6.2, BR6.9) and the FROM node IDs in branch
6 and 11 (BR6.6, BR6.11).
[0140] Using the voltage branch-to-node data of table 5, the
topology processor 570 may generate groups of nodes for voltage
consistency checks and/or voltage measurement refinement. Table 6
may represent a voltage node group generated from Table 5:
TABLE-US-00006 TABLE 6 Group of Nodes for Voltage Topology N6.1,
N6.3 N6.2 N6.4
[0141] In Table 6, only nodes having voltage measurements thereon
may be included (e.g., only node IDs N6.1-N6.4). Nodes 1 and 3
(N6.1, N6.3) are in the same group, since after closing branch 9
(BR6.2), these nodes may be at a common voltage level.
[0142] FIG. 7A is a flow diagram of one embodiment of a method 700
for processing merged branches in a current processor
branch-to-node data structure. At step 710, a branch-to-node data
array may be obtained. Step 710 may comprise accessing the topology
data (e.g., the input 572 of FIG. 5). At step 720, the topology
data may be used to initialize a current processor branch-to-node
data array. As discussed above, the current processor
branch-to-node data of step 720 may be initialized by analyzing
static and dynamic topology data to determine the state of the
interconnections therein. The result of step 720 may be one or more
branch-to-node data arrays as depicted in tables 1, 2, and 3.
[0143] At step 730, method 700 may loop through every branch
defined in the current topology branch-to-node data array obtained
at step 720. At step 740, the merged status of a branch may be
determined. As discussed above, for a current branch-to-node data,
a branch may be merged if the topology data indicates that the
branch is closed (e.g., element 254 of FIG. 2B, "closed" node has
value TRUE) and/or the closed quality status is false (e.g.,
element 255 of FIG. 2B, "closed_quality_status").
[0144] At step 750, the branch-to-node data structure may be
updated to reflect the merged status of the branch. As discussed
above, this may comprise replacing all instances of the TO node ID
in the merged branch with the FROM node ID in the current
branch-to-node data structure.
[0145] At step 760, method 700 may determine whether all the
branches in the branch-to-node data have been processed per steps
740-750. If not, the flow may continue at step 740 where the next
branch in the current processor branch-to-node data may be
processed; otherwise, the flow may terminate at step 770.
[0146] FIG. 7B is a flow diagram of one embodiment of a process 701
for merging nodes in a voltage processor branch-to-node data
structure. Process 701 may be substantially the same as process 700
discussed above in conjunction with FIG. 7A with the exception of
step 741 (740 in FIG. 7A).
[0147] At step 741, a branch in the voltage branch-to-node data,
may be merged if the topology data indicates that the branch is
closed (e.g., element 254 of FIG. 2B, "closed" node has a value of
TRUE) and/or the closed quality status is true (e.g., element 255
of FIG. 2B, "closed_quality_status"). If step 740 determines that
the branch is merged, the flow may continue to step 750; otherwise,
the flow may continue to step 760. After determining the status of
each branch in the voltage processor branch-to-node array
substantially as described above, the flow may terminate at step
771.
[0148] After initializing and processing the current branch-to-node
data and the voltage branch-to-node data, the topology processor
570 may create one or more node groups of nodes (e.g., groups such
as the current topology group of table 3 and the voltage topology
group of table 6).
[0149] The current group(s) may be based upon the current
branch-to-node data structure and may comprise group(s) with
current measurements on every branch leaving the group. A current
processor module (e.g., current processor module 580 of FIG. 5) may
use these group(s) to perform current consistency checks, KCL
check, measurement refinement, and the like.
[0150] The voltage group(s) may be based upon the voltage
branch-to-node data structure and may comprise group(s) of nodes. A
voltage processor module (e.g., voltage processor module 590 of
FIG. 5) may use these group(s) to perform voltage consistency
checks, measurement refinement, and the like.
[0151] The current group(s) may be formed from a current node
vector. In a current node vector, nodes may be grouped by whether
they have been "merged" with one or more other nodes in the array.
For example, if a particular node (e.g., node X) is merged into a
branch (it is the TO node ID of a merged branch), the number of
nodes associated with node X may be zero (0). If node X is by
itself (e.g., not merged, nor has any nodes merged therein), the
number of nodes associated with node X may be one (1). If other
nodes are merged into node X (e.g., it is the FROM node ID of a
merged branch), the number of nodes associated with node X may be
the number of merged nodes plus one (1).
[0152] Similarly, the voltage group(s) may be formed from a voltage
node vector. In the voltage node vector, nodes may be grouped by
whether they have been "merged" with one or more other nodes in the
array. For example, as above, if a particular node (e.g., node Y)
is merged with another node due to a closed branch (it is the TO
node of a merged branch), the number of nodes associated with node
Y may be zero (0). If the node Y is by itself (e.g., not merged
into another node, nor has any nodes merged therein), the number of
nodes associated with node Y may be one (1). If other nodes are
merged into node Y (e.g., it is the FROM node of a merged branch),
the number of nodes associated with node Y may be the number of
merged nodes plus one (1).
[0153] FIG. 8 is a flow diagram of one embodiment of a method 800
for generating a current node vector is depicted. At step 810, the
node vector may be initialized from SEPSN topology data (static
and/or dynamic) and a current branch-to-node data structure may be
obtained. In one embodiment, the input data received at step 810
may comprise a current branch-to-node data array produced by method
700 of FIG. 7A.
[0154] At step 815, each node in the topology may be processed
(e.g., steps 820 through 835 may be performed on each node in the
topology), and at step 820, each branch in the branch-to-node data
arrays may be processed (e.g., steps 825 through 830 may be
performed for each branch).
[0155] At step 825, process 800 may determine if the TO node ID and
the FROM node ID in the branch being processed are the same as the
current node (e.g., if the node was merged per process 700 of FIG.
7A). If so, the flow may continue to step 830; otherwise, the flow
may continue to step 835.
[0156] At step 830, the TO ID and the FROM ID branch nodes may be
added to a current node vector (or any other data structure capable
of holding a number of entries), which may contain nodes belonging
to the same group (hereafter current node vector). The current node
vector may comprise one or more pointers (or other data references)
to the nodes comprising the group. The current node vector may
comprise a counter indicating the number of nodes in a particular
entry. Accordingly, at step 830, the counter may be incremented if
necessary.
[0157] At step 835, method 800 may determine whether there are
additional branches to process. If so, the flow may continue to
step 820; otherwise, the flow may continue to step 840. At step
840, method 800 may determine whether there are additional nodes to
process. If so, the flow may continue to step 815; otherwise, the
flow may continue to step 845.
[0158] At step 845, method 800 may again iterate over all of the
nodes in the topology (e.g., may perform steps 850 through 860 on
each node). At step 850, process 800 may determine whether the node
is in the current node vector (e.g., linked to and/or referenced by
an entry in the current node vector). If the node is in the current
node vector, the flow may continue to step 860; otherwise, the flow
may continue to step 855.
[0159] At step 855, the node may be added to the current node
vector. This step may be required where the node is "by itself". As
such, at step 855, the node may be added to a new node vector
comprising only the node itself.
[0160] At step 860, process 800 may determine whether there are
additional nodes to process. If so, the flow may continue at step
845 where the next node may be processed; otherwise, the flow may
terminate at step 865.
[0161] As described above, method 800 of FIG. 8 may be used to
generate a current node vector. In addition, method 800 may
generate a voltage node vector. These vectors may be generated
separately (e.g., in separate iterations of method 800) or
concurrently (e.g., in the same iteration of method 800).
[0162] FIG. 8B is a flow diagram of a method 801 for generating a
voltage node vector. Method 801 may be performed substantially as
described above: at step 811, a voltage node vector may be
initialized; at step 816, method 801 may iterate over all of the
nodes in the topology; at step 821, each branch in the voltage
branch-to-node data structure may be processed; and, at step 826,
each node is compared to each branch in the voltage branch-to-node
data structure. At step 826, the node ID may be compared to the TO
node ID and the From node ID in the voltage branch-to-node data
structure. If the condition of step 826 is true (the node ID
matches the TO node ID and the FROM node ID), the flow continues to
step 831 where the node is added to the voltage node vector;
otherwise, the flow continues to step 836.
[0163] After processing each node over steps 821-831, the flow
continues to step 846 where each node in the topology is processed.
At step 851, method 801 determines whether the node is in the
voltage node vector. If not, the flow continues to step 856 where
the node is added to the voltage node vector substantially as
described above; otherwise, the flow continues to step 861 where
the next node is processed.
[0164] Referring again to FIG. 5, the topology processor 570 may
perform an embodiment of methods 700 and 800 on the topology data
included in branch input data 572. The result may be a current
branch-to-node data structure, a voltage branch-to-node data
structure, a current node vector, and a voltage node vector.
Applying process 800 to the SEPSN 600 depicted in FIG. 6, and
current branch-to-node data structure depicted in Table 2, may
result in a node vector 900 depicted in FIG. 9.
[0165] FIG. 9 depicts exemplary data structures 900 as processed by
a topology processor (e.g., topology processor 570 of FIG. 5). A
data structure 903 may represent a current branch-to-node data
structure corresponding to the SEPSN depicted in FIG. 6. As such,
data structure 903 may represent an equivalent set of data as
depicted in Table 1. Data structure 903 is replicated in FIG. 9 to
allow for a better depiction of the current node vector 910. The
data structure 905 may represent a current branch-to-node data
structure after merging branch 10 (e.g., BR6.10 of FIG. 6). Data
structure 905 may represent an equivalent set of data as depicted
in Table 2. Data structure 905 is replicated in FIG. 9 to allow for
a better depiction of the current node vector 910.
[0166] As discussed above, the current topology branch-to-node data
903 may represent the current-branch topology of the SEPSN 600 of
FIG. 6 before closing branch BR6.10. After merging branch BR6.10,
references to the merged node 2 (N6.2) may be replaced with node 1
(N6.1). The current branch-to-node data 905 depicts an update to
the branch-to-node data reflecting this change. In the updated
current branch-to-node data 905, references to node 2 (N6.2) in
branch 3-5 (BR6.3-BR6.5) have-been replaced with references to node
1 (N6.1). In addition, the TO node ID in branch 10 (BR6.10) has
been changed to node 1 (N6.1).
[0167] The current node vector 910 depicts one embodiment of a
current node vector structure 910 corresponding to branch-to-node
data structures 903 and 905. The current node vector 910 may be
formed by applying an embodiment of method 800, depicted in FIG. 8,
to the topology of FIG. 6 and its corresponding current
branch-to-node data 905.
[0168] The current node vector 910 comprises a group node listing
920. The group node list 920 comprises a group entry (e.g., G.1)
for each node in the topology. The group node list 920 depicted in
FIG. 9 corresponds to a SEPSN having eleven (11) nodes, as such,
the group node list 920 comprises eleven (11) group entries 920.
Each entry G.1 through G.11 in the group list 920 comprises: a
group identifier; the number of nodes in the group; and a pointer
or other reference into a node vector 940. For example, group G.1
may comprise a group identifier "1" G.1 A, the number of nodes in
the group G.1 B (two (2)), and a reference G.1C to the node vector
940.
[0169] After merging branch 10 (B6.10) in the SEPSN 600 of FIG. 6,
a group comprising node 1 (N6.1) and node 2 (N6.2) may be formed.
This may be reflected by group 1 (G.1) of the current node vector
910. Group G.1 may be identified as group 1 at entry G.1A. Entry
G.1B may indicate that there are two (2) nodes comprising group 1.
Entry G.1C may comprise a pointer or other reference into node
vector 940. The reference of G.1C may point to the first node in
the group (i.e., node 1 (N6.1)). Using the reference of G.1C and
the number of nodes indicator G.1B, the nodes comprising the group
can be determined by traversing node vector G.1B two (2) times. As
such, group G.1 may comprise nodes demarcated by 940.1, N6.1, and
N6.2. Although 910 is depicted as using an array-based relative
offset addressing and/or referencing scheme, one skilled in the art
would recognize that any data reference scheme could be used under
the teachings of this disclosure. As such, this disclosure should
not be read as limited to any particular data structure 910 format
and/or data referencing technique.
[0170] As discussed above, a group whose node has been merged into
another group may comprise zero (0) nodes. Group two (2) G.2 is
such a group. This is because in the FIG. 9 embodiment, node 2
(N6.2) has been merged into group 1 (G.1) with the closing of
branch 10 (BR6.10). As such, the number of nodes in group G.2 is
zero and the reference into the reference vector may be zero (0)
and/or null.
[0171] As discussed above, a group may comprise a single node.
Groups G.3 through G.11 are such groups. Accordingly, G.11
comprises one (1) node (N6.11) and points to the node vector
location comprising node eleven (11) (N6.11) in node vector
940.
[0172] A voltage node vector may be generated using data structures
substantially equivalent to data structures 903, 905, 910, and 940
depicted in FIG. 9.
[0173] Referring again to FIG. 5, the topology processor 570 may
produce an operating topology of the SEPSN comprising a current
topology 582 for the current processor 580. The current topology
582 may comprise a current branch-to-node data array, a current
node vector, and associated node vector. The current processor 580
may also receive current measurements 584. As discussed above, the
current measurements 584 may be obtained by one or more PMUs (not
shown) and/or PMCUs or relay (not shown) disposed within a
substation power system network, the current measurements 584 may
be time aligned substantially as described above. Also as discussed
above, the current topology data 582 and current measurements 584
may be input to the current processor 580 as a tree structure
(e.g., the branch input list 220 described in conjunction with FIG.
2B).
[0174] Upon receiving current topology data 582 and current
measurement data 584, the current processor 580 may be configured
to inter alia, scale each current measurement by its corresponding
correction factor, perform a consistency check on the current
measurements, and refine the measurements. FIG. 10 depicts a flow
diagram of one embodiment of a method 1000 for performing these
functions.
[0175] Turning now to FIG. 10, at step 1010, method 1000 may
receive a current topology, which, as discussed above, may comprise
a current topology of the SEPSN (e.g., comprise a current
branch-to-node data, etc.). In addition, the method 1000 may
receive one or more current measurements associated with the
current topology.
[0176] At step 1020, one or more correction factors may be read.
The correction factors read at step 1020 may be read from the
topology data discussed above. The correction factors may be used
to normalize the current measurements with respect to the topology
data received at step 1010. FIG. 11 depicts one embodiment of a
SEPSN topology that may be used to illustrate the use of one or
more current correction factors at step 1020.
[0177] Turning now to FIG. 11, node 1110 may be in electrical
communication with node 1120 via a power transmission conductor
1130 to allow a current /.sub.1132 to flow therebetween. An IED
1112, such as a PMU and/or PMCU or relay, may be communicatively
coupled to transmission conductor 1130 at or near node 1110 to
measure a current /.sub.1112 thereon. Another IED 1122, which may
be an IED, relay, a PMU and/or PMCU, may be communicatively coupled
to transmission conductor 1130 at or near node 1120 to measure a
current /.sub.1122 thereon. Given the polarities of IED 1112 and
1122, and assuming nonexistent and/or negligible measurement error,
the measured currents /.sub.1112 and /.sub.1122 be the inverse of
one another as shown in Equation 1.1:
I.sub.1112=-.sub.1122='.sub.1132 Eq. 1.1
[0178] Given Equation 1.1, a first measurement correction factor
for the measurement obtained at IED 1112, k.sub.1 may be 1 at
0.degree. since the current flowing from node 1110 to node 1120 may
cause a secondary current to enter IED 1112. Similarly, a second
measurement correction factor for the measurement obtained at IED
1122, k.sub.2 may be 1 at 180.degree. (i.e., -1) since the primary
current 1132 flowing from node 1110 to node 1120 may cause a
secondary current to leave IED 1122. Using these correction
factors, Equation 1.1 may be rewritten as shown in Equation
1.2:
k.sub.1I.sub.1112=k.sub.2I.sub.1122, k=, k.sub.2=- Eq. 1.2
[0179] The current correction factors discussed above may also be
adapted to take into account properties of the device (e g.,
current transformer) used to obtain the current measurement. For
example, a current correction factor may account for a turn ratio
of the current transformer and/or IED used to obtain a current
measurement (e.g., 1112 and/or 1122 of FIG. 11). Similarly, a
current correction factor may address any phase shifting introduced
by the current transformer and/or IED. This may allow the current
correction factor to normalize measurements obtained by different
current transformer types and/or configurations. As such, a current
correction factor may comprise a magnitude correction factor and/or
a phase correction factor. The magnitude and/or phase component of
a particular current correction factor may be derived from any of
the current measurement properties discussed above including, but
not limited to: an orientation of the current measurement in a
current topology; a current magnitude adjustment (e.g., due to
current transformer turn ratio or the like); a current phase
adjustment (e.g., due to current transformer phase shift);
combinations thereof; and the like.
[0180] Voltage correction factors may be used to normalize voltage
measurements obtained by the IEDs (e.g., IED 1112 and/or 1122 of
FIG. 11). Like the current correction factors discussed above, the
voltage correction factors may be used to address voltage
measurement differences introduced by the transformer and/or IED
used to obtain the measurements (e.g., magnitude, phase shift, and
the like). Voltage correction factors may also be used to address
the orientation of voltage measurements in a voltage topology
(e.g., account for the polarity of a voltage measurement and the
like). In addition, a voltage correction factor may address a
voltage base value of a measurement (e.g., the measurement may be
taken relative to a voltage base).
[0181] Referring again to FIG. 10, at step 1020, method 1000 may
read and/or otherwise determine correction factors for every
current measurement received at step 1010. In one embodiment, the
correction factors may be static, such that they only need to be
read or determined once. In other embodiments, one or more factors
may be recalculated as the topology of the SEPSN changes (e.g., in
response to dynamic topology data). Alternatively, correction
factors associated with one or more measurements may be user
supplied and stored in data structure, such as data structure 210
of FIG. 2B (e.g., element 263 of FIG. 2B). After determining the
relevant current correction factors, the flow may continue to step
1030.
[0182] At step 1030, the current measurements received at step 1010
may be scaled (e.g., normalized) using the correction factors of
step 1020. The scaled current measurements may be stored in a data
structure for use in subsequent steps (e.g., steps 1040-1060) of
method 1000. The flow may then continue to step 1040.
[0183] At step 1040, method 1000 may perform a current measurement
consistency check on the scaled current measurements. One
embodiment of a method to perform such a check is described below
in conjunction with FIGS. 12A and B. The flow may then continue to
step 1050.
[0184] At step 1050, method 1000 may refine one or more of the
current measurements. One embodiment of a method for refining
current measurements is described below in conjunction with FIGS.
13A and 13B. The flow may then continue to step 1060.
[0185] At step 1060, method 1000 may perform current unbalance and
symmetrical component checks. One embodiment of a method for
performing these checks is described below in conjunction with FIG.
14. The flow may then terminate at step 1070.
[0186] FIG. 12A is a flow diagram of one embodiment of a method
1200 for performing a current consistency check. At step 1210,
topology data and one or more scaled current measurements may be
received. This data may be provided by an output of method 1100
described above in conjunction with FIG. 11.
[0187] At step 1220, method 1200 may iterate each branch and phase
within the topology data received at step 1210. As such, method
1200 may perform steps 1230 through 1260 for each branch and phase
within the topology data of step 1210.
[0188] At step 1230, method 1200 may determine whether current
measurements are available for the branch. This information may be
provided in the topology data of step 1210 (e.g.,
number_of_current_measurements entry 256 of FIG. 2B). If there are
measurements available in the branch, the flow may continue to step
1240; otherwise, the flow may continue to step 1270.
[0189] At step 1240, one or more scaled current measurements
associated with the branch may be obtained. The scaled current
measurements of step 1240 may be made available by another process
(e.g., process 1100 described above in conjunction with FIG. 11) or
may be computed at step 1240 given one or more correction factors
provided in the topology data of step 1210.
[0190] At step 1250, a current measurement median may be
determined. This may comprise computing the median from the
available current measurements. In an alternative embodiment, step
1250 may use the average
[0191] At step 1260, a consistency check may be performed on each
of the current measurements for the current branch. This
consistency check may comprise calculating a difference between
each current measurement for the branch to the median measurement
value of the branch (calculated at step 1250) against a consistency
threshold value per Equation 1.4:
|c.sub.i-|< Eq. 1.4
[0192] In Equation 1.4, c.sub.i may be a branch current measurement
corresponding to one or more current phases, .gamma..sub.B may be
the median or mean current measurement for the branch and
.epsilon..sub.B may be the consistency threshold for the phase and
branch. If the inequality of Equation 1.4 is satisfied, the flow
may continue to step 1280; otherwise, the flow may continue at step
1270.
[0193] At step 1270, a consistency alarm may be set indicating that
one or more current measurements and/or phases of a current
measurement fail to satisfy the consistency check of step 1260. The
alarm may identify the branch, phase, and/or the one or more
measurements that produced the inconsistency. The flow may continue
to step 1280.
[0194] At step 1280, method 1200 may determine whether there are
additional branches to process. If so, the flow may continue to
step 1220; otherwise, the flow may terminate at step 1290.
[0195] Turning now to FIG. 12B, a visual depiction of process 1200
is provided. In FIG. 12B, measurements 1211 corresponding to a
particular branch may be plotted on plot 1201, comprising an
imaginary axis 1203 and a real axis 1205. A median value 1213 of
the measurements 1211 may be determined. A consistency threshold
associated with the phase and branch may be depicted as 1221. The
radius of 1221 may correspond to the consistency threshold value. A
measurement 1215 that differs from the mean and/or media value 1213
by more than a threshold 1221 may cause a consistency alarm to be
asserted.
[0196] Turning now to FIG. 13, one embodiment of a process 1300 for
performing a KCL check and measurement refinement is depicted.
[0197] At step 1310, topology data and two (2) or more scaled
current measurements may be received. The data received at step
1310 may be provided by an output of a method, such as 1100
described above in conjunction with FIG. 11.
[0198] At step 1320, method 1300 may iterate over each node (e.g.,
each entry in a current merged node array) in the topology data
received at step 1310. At step 1325, method 1300 may iterate over
each phase measurement available for the node and/or group of step
1320 (e.g., each phase of a three-phase, phase current, or other
signal measurement).
[0199] At step 1330, method 1300 may determine whether a KCL check
may be performed on the node. In some embodiments, a KCL check may
require that all currents reaching a node be available. This
requirement may be imposed since method 1300 may operate under the
axiom that the sum of currents reaching a node should be
substantially zero (0) per Kirchhoffs Current Law (KCL). If one of
the current measurements is unavailable, however, the KCL axiom may
not hold, and as such, process 1300 may not yield meaningful
results. Similarly, where the node is part of a node group (e.g.,
as defined by the current node vector) a KCL check may be possible
if all nodes in the group are KCL nodes (e.g., have current
measurements on their associated branches). If a KCL check can be
performed on the node and/or node group, the flow may continue to
step 1340; otherwise, the flow may continue to step 1380 where the
next node and/or phase may be processed.
[0200] At step 1340, the scaled current measurements reaching the
node may be summed and compared to a KCL threshold value per
Equation 1.5:
|.SIGMA..sub.=c.sub.i|<KCL_thre Eq. 1.5
[0201] In Equation 1.5, N may be the number of branches reaching a
particular node group, c.sub.i may be a particular phase-current
measurement, and KCL_thre may be the KCL threshold (e.g., instance
231 of FIG. 2B).
[0202] At step 1350, method 1300 may determine whether the
inequality of Equation 1.5 is satisfied. If the inequality is
satisfied (i.e., the absolute value of the sum is less that the KCL
threshold), the flow may continue to step 1360; otherwise, the flow
may continue to step 1370 where the next node and/or phase may be
processed.
[0203] At step 1360, the current measurements associated with the
node may be flagged appropriately (e.g., marked as satisfying the
threshold of step 1340), and the flow may continue to step 1365
where the phase-current measurements may be refined.
[0204] At step 1365, the phase-current measurements may be refined.
In one embodiment, refinement may comprise refining the
measurements relative to an overall error metric .epsilon.. In
particular, the phase-current measurements may be refined such that
the overall error .epsilon. is minimized. One embodiment of an
approach to minimizing error is described below in conjunction with
FIG. 13B.
[0205] FIG. 13B depicts a segment 1301 of a SEPSN. The segment 1301
may comprise a node 1311 having three branches connected thereto,
each comprising a scaled current measurement: 1313 (A.sub.1), 1315
(A.sub.2), and 1317 (A.sub.3). The current measurements 1313, 1315,
and 1317 may correspond to a single phase of a three-phase, current
signal reaching the node 1311.
[0206] As discussed above, the threshold condition of node 1311 may
be given as Equation 1.6:
|.SIGMA..sub.=A.sub.i|<KCL_thre Eq. 1.6
[0207] To refine the measurements 1313, 1315, and 1317, the overall
error .epsilon. may be calculated per Equation 1.7:
= i = ? ? + I 1 - A 1 + I 2 - A 2 + I 3 - A 3 ? indicates text
missing or illegible when filed Eq . 1.7 ##EQU00001##
[0208] In Equation 1.7, I may represent the metered and/or refined
phase-current measurements reaching node 1311. Accordingly,
Equation 1.7 equally distributes any measurement error between the
three current measurements 1313 (A.sub.1), 1315 (A.sub.2), and 1317
(A.sub.3).
[0209] To obtain a solution to minimize .epsilon., Equation 1.7 may
be rewritten in matrix form as shown in Equation 1.8:
[ 1 1 1 1 0 0 0 1 0 0 0 1 ] I 1 I 2 I 3 ] - [ 0 A 1 A 2 A 3 ] = ? ?
indicates text missing or illegible when filed Eq . 1.8
##EQU00002##
[0210] In Equation 1.8, the problem becomes one of minimizing error
.epsilon.. To do so, the pseudo inverse of the matrix of Equation
1.8 may be obtained, and Equation 1.8 may be rewritten as Equation
1.9:
[ I 1 I 2 I 3 ] = [ 3 4 - 1 4 - 1 4 - 1 4 3 4 - 1 4 - 1 4 - 1 4 3 4
] A 1 A 2 A 3 ] Eq . 1.9 ##EQU00003##
[0211] The structure of Equation 1.9 may remain constant as the
number of currents reaching the node (e.g., node 1311) changes. As
such, an equation for each entry in the matrix of equation 1.9 may
be determined per Equation 1.10:
a i , j = { n / ? a + 1 , if i = j - 1 / ? a + 1 , if i .noteq. j ?
indicates text missing or illegible when filed Eq . 1.10
##EQU00004##
[0212] In Equation 1.10, n may represent the number of currents
reaching a particular node and i and j may be the indices of the
matrix in Equation 1.9. As such, for node 1311 of FIG. 13B, n may
be three (3).
[0213] To refine the phase-current estimates, equation 1.10 may be
applied to obtain entries in the matrix of Equation 1.9, and then
multiply the matrix by the measurement vector (i.e., the A.sub.1-n
vector). A closed form may be written as Equation 1.11:
I i = A i - j = ? ? j ? , i = , 2 , , n ? indicates text missing or
illegible when filed Eq . 1.11 ##EQU00005##
[0214] As such, at step 1365, equation 1.11 may be applied to the
phase-current measurements A.sub.i to thereby obtain refined
measurements I.sub.i. The refined measurements may be output to a
HMI interface (e.g., output 585.1 in FIG. 5 to an HMI 470 of Figure
4).
[0215] At step 1370, method 1300 may determine whether there are
remaining current phases to processes. If so, the flow may continue
to step 1325 where a next set of phase-current measurements of a
multi-phase current (e.g., three (3)-phase current) may be
processed; otherwise, the flow may continue to step 1380.
[0216] At step 1380, method 1300 may determine whether there are
remaining nodes to process. If so, the flow may continue to step
1320 where the next node and/or node group may be processed;
otherwise, the flow may terminate at step 1390.
[0217] Turning now to FIG. 14, a flow diagram of one embodiment of
method for performing a current unbalance, symmetrical component
check is depicted.
[0218] At step 1410, topology data and one (1) or more scaled
current measurements may be received. The data received at step
1410 may be provided by an output of a method, such as 1100
described above in conjunction with FIG. 11.
[0219] At step 1420, method 1400 may iterate over all of the
branches in the topology data received at step 1410. At step 1430,
method 1400 may determine whether all phase current measurements of
the particular branch are available. If so, the flow may continue
at step 1440; otherwise, the flow may continue at step 1480 where
the next branch may be processed.
[0220] At step 1440, an unbalanced branch check may be performed.
The check of step 1440 may comprise determining a reference current
(/.sub.REF) value, which, in some embodiments, may be the median
value of the phase current magnitudes at the branch. Alternatively,
the /.sub.REF may be an average value
[0221] At step 1450, a ratio of the magnitude of each phase (e.g.,
each phase of a three (3)-phase current) to the reference current
/.sub.REF may be calculated per equation 1.13:
unb A = I A I REF - 1 Eq . 1.13 ##EQU00006##
[0222] In Equation 1.13, unb.sub.A may be the magnitude of the
ratio of a magnitude of. the A phase current measurement (I.sub.A)
to the reference current, /.sub.REF minus 1. Equation 1.13, may be
used to calculate the unbalance for each current phase (e.g.,
phases A, B, and C of a three (3)-phase current). The unbalance of
Equation 1.13 may be expressed in terms of a percentage as in
Equation 1.14:
unb A = I A I REF 100 Eq . 1.14 ##EQU00007##
[0223] At step 1460, each of the phase-current unbalances may be
compared to a user-defined unbalance threshold value associated
with the branch. The topology data received at step 1410 may
include these threshold values (e.g., i_unb_thre element 257.2 of
FIG. 2B). If any of the phases exceeds its respective unbalance
threshold, the flow may continue at step 1465; otherwise, the flow
may continue to step 1470.
[0224] At step 1465, a current unbalance alarm may be set on the
current measurement. The alarm of step 1465 may be set for all
phases of a multi-phase current (e.g., three (3)-phase current)
and/or only the phases that fail to satisfy the unbalance threshold
of steps 1450. The flow may then continue to step 1470.
[0225] At step 1470, the symmetrical components (negative,
positive, and zero) of the three-phase current may be calculated.
At step 1473, the symmetrical components may be compared to the
user-defined threshold values associated with the branch
symmetrical components. The topology data received at step 1410 may
include these threshold values (e.g., as one or more values in data
structure 210 of FIG. 2B). If one or more symmetrical components
exceeds its associated threshold, the flow may continue to step
1475; otherwise, the flow may continue to step 1480.
[0226] At step 1475, the symmetrical component alarm(s) may be set
on the current and branch. After setting the alarm, the flow may
continue to step 1480.
[0227] At step 1480, the next unprocessed branch (if any) may be
checked, and the flow may continue to step 1420. If no branches
remain to be processed, the flow may terminate at step 1490.
[0228] Referring again to FIG. 5, current processor 580 may perform
method 700 (described above in conjunction with FIG. 7), which may
comprise applying one or more correction factors to current
measurements 584, computing a current measurement mean or median
for each branch, checking branch current consistency, refining
current measurements, and checking current balance and symmetrical
components as described in conjunction with FIGS. 8-14.
[0229] If current refinement is possible, current processor 580 may
output refined current values 585.1. In addition, the checks
mentioned above (e.g., consistency, KCL, unbalance, etc.) may
comprise setting an alarm relating to one or more checked current
phases, currents, and/or branches. As such, after processing one or
more alarms 585.2 may be output from current processor 580. As
discussed above in conjunction with FIG. 4, these alarms may be
routed to a HMI module (e.g., element 470 of FIG. 4) and/or a local
PMCU (e.g., element 480). A HMI may display one or more alarms to
an operator of the state and topology processor, and a local PMCU
may use the alarm data to invoke one or more protective functions
including, but not limited to: sending an alarm, tripping one or
more circuit breakers, changing the configuration of one or more
switches, removing and/or adding one or more loads, or the
like.
[0230] Current unbalance percentage values calculated by current
processor module 580 (e.g., per method 1400 described above in
conjunction with FIG. 14) may be provided via output 585.3. In
addition, symmetrical components associated with each branch
current may be provided via output 585.4. These outputs, along with
the refined measurements and alarms discussed above, may be made
available to a HMI and/or local PMCU to provide monitoring and
protection to a SEPSN.
[0231] The voltage processor module 590 of STP 560 may receive
voltage measurement data 594 and voltage topology data 592 from the
topology processor 570. As discussed above, this data may be
conveyed via a data structure similar to the tree data structure
described above in conjunction with FIGS. 2B and 2C. The voltage
processor 590 may be configured to apply voltage correction factors
to the voltage measurement data 594, calculate median phase-voltage
measurement values at each node in topology data 592, perform one
or more voltage consistency checks, refine the voltage measurements
594, and perform symmetrical component analysis on voltage
measurements 594.
[0232] Turning now to FIG. 15, a flow diagram of one embodiment of
a method 1500 for monitoring phrase voltages in a SEPSN is
depicted. A voltage processor module, such as voltage processor
module 590 of FIG. 5, may perform method 1500.
[0233] At step 1510, method 1500 may receive network topology data
(e.g., a node list data structure and/or voltage merged node
group), and/or one or more phase voltage measurements. The topology
and phase voltage measurement data may be conveyed in a data
structure similar to the "input data" data structure described
above in conjunction with FIGS. 2B and 2C.
[0234] At step 1520, method 1500 may iterate over all of the node
groups in the topology data received at step 1510 (e.g., all node
groups in the merged group data structure).
[0235] At step 1525, one or more correction factors may be applied
to the voltage measurements received at step 1510. The correction
factors may be stored in the network topology data of step 1510 in,
for example, voltage correction factors 277 of FIG. 2C.
[0236] At step 1530, a median value for each phase-voltage
measurement may be determined. In alternative embodiments, an
average phase-voltage measurement may be calculated at step
1530.
[0237] At step 1540, a voltage consistency check may be performed.
The voltage consistency check of step 1540 may be similar to the
current consistency check described above in conjunction with FIG.
12A. As such, the consistency check may comprise calculating a
difference between each phase-voltage measurement of a particular
node and/or node group to the median phase-voltage measurement
calculated at step 1530. The consistency check of step 1540 may be
performed for all phases of each phase voltage measurement
available at a particular node group. At step 1540, if the
difference between the measured voltage and the measurement median
is greater than a user-defined threshold (e.g., defined in data
structure 210 described above in conjunction with FIGS. 2A-C), the
flow may continue to step 1550; otherwise, the flow may continue to
step 1560.
[0238] At step 1550, a voltage consistency alarm may be set. The
alarm may identify the voltage phase, measurement, node, and/or
node group corresponding to the alarm. The flow may then continue
to step 1560.
[0239] At step 1560, the symmetrical components for each group
and/or node phase-voltage measurement may be calculated. At step
1570, these components may be compared to corresponding
user-defined symmetrical component threshold(s). These thresholds
may be stored in the data received at step 1510 (e.g., in an input
data structure 210 described above in FIGS. 2B and 2C). If one or
more components exceed its associated threshold, the flow may
continue at step 1575; otherwise, the flow may continue to step
1580.
[0240] At step 1575, the symmetrical component alarms may be set.
These alarms may identify the node and/or node group and/or the
measurement producing the alarms. The flow may then continue to
step 1580.
[0241] At step 1580, method 1500 may determine whether there are
nodes and/or node groups remaining to process. If so, the flow may
continue to step 1520 where the next node and/or node group may be
processed; otherwise, the flow may terminate at step 1590.
[0242] Referring back to FIG. 5, the voltage processor 590 may
perform method 1500 (described above in conjunction with FIG. 15),
which may comprise applying one or more correction factors to
voltage measurements 595, computing a voltage measurement median or
mean for each node and/or node group, checking measurement
consistency, and/or performing a symmetrical components check.
[0243] The checks discussed above (e.g., consistency, symmetrical
component, etc.) may comprise setting an alarm relating to one or
more phase voltages on one or more node groups, voltages, nodes,
and/or node groups. As such, after processing, one or more alarms
595.2 may be output from voltage processor 590. As discussed above,
alarm(s) 595.2 may be routed to HMI module (e.g., HMI 470 of FIG.
4) for display to a user. In addition, the alarms may be routed to
a local PMCU (e.g., PMCU 480 of FIG. 4), which may invoke one or
more protective functions responsive to the alarm(s) 595.2. These
protective functions may include, but are not limited to: sending
an alarm, tripping one or more circuit breakers, changing the
configuration of one or more switches, removing and/or adding one
or more loads, or the like. Additionally, one or more symmetrical
components corresponding to voltage measurements 582 may be output
at 595.3.
[0244] Referring to FIG. 4, the DP 420 may be communicatively
coupled to a human machine interface (HMI) 470. As discussed above,
the HMI 470 may be used to display monitoring information to a user
of the DP 420. Such information may comprise refined measurements,
alarms, and the like.
[0245] FIG. 16 depicts one embodiment of an visualization interface
1600. The visualization interface 1600 may be displayed within a
computer display and/or application 1610. The application 1610 may
be executable on a general and/or special purpose computing device
comprising a processor (not shown), input devices (not shown), such
as a keyboard, mouse, or the like, data storage (not shown), such
as a disc drive, memory, or the like, and one or more output
devices (not shown), such as display, audio speakers, or the like.
The application 1610 may be presented on the display of the
computing device (not shown) and may comprise custom and/or general
purpose software communicatively coupled to a state and topology
processor and/or time aligned data processor (e.g., the DP 420
and/or STP 460 of FIG. 4).
[0246] The application 1610 may be configured to display a portion
of the substation power system network to which the STP is
connected. The display of the power system may be based upon
topology data received from the DP and/or STP. In addition, the
topology display may comprise the real-time operating topology as
determined by the DP and/or STP. As such, the display may show the
current state of one or more breakers, switches, and other
connective components in the power system.
[0247] The application 1610 may display refined current and/or
voltage measurements 1622 and 1624 received from the DP and/or STP.
Although FIG. 16 depicts only two (2) such measurements displayed
on the application 1610, one skilled in the art would recognize
that any number of measurements could be displayed in the
application 1610 according to the configuration of the STP and/or
the power system network.
[0248] The refined measurements 1622 and 1624 may be obtained
substantially as described above. For example, a refined current
measurement may represent a combination of multiple current
measurements as refined using an error minimization metric.
Similarly, refined voltage measurements may comprise a median,
average, and/or error minimized voltage measurements.
[0249] One or more alarms 1612, 1614, and/or 1616 may be displayed
in the application 1610. The alarms displayed on one or more
components of the electrical power system, such as electrical power
system nodes (e.g., N1, N2, and so on), electrical power system
branches, bus bars, or the like.
[0250] The alarms 1612, 1614, and/or 1616 may be generated
responsive to any one or more of the alarm conditions described
above (e.g., KCL, symmetrical components, unbalance, or the like).
The alarms 1612, 1614, and/or 1616 may related to current
conditions, voltage condition, branch conditions, or the like.
[0251] In addition, electrical power system components and/or
measurements thereon, which have been verified as working properly
may be so marked as shown 1632. Element 1632 indicates that the
state of the particular branch and/or the measurements received
therefrom are correct.
[0252] The application 1610 may be selectable such that selection
of a particular node, branch, and/or alarm may display detailed
information relating to the respective component. For example,
selection of the alarm 1616 on branch B3 may cause application 1610
to display details regarding the measurements and/or alarms
associated with the branch B3. One example of such a display 1700
is provided in FIG. 17.
[0253] As shown in FIG. 17, an application 1710 may display
additional information relating to a particular component within
the power system network displayed the application 1610. FIG. 17
displays details relating to a branch B3 shown in FIG. 16.
[0254] The application 1710 may comprise a measurement consistency
check 1720 component, which may display each of the measurements
1721 and 1723 available at the particular component. Each
measurement 1721 and 1723 may comprise a three-current measurement
1722 and 1724. A refined current measurement may be displayed at
1726, which may comprise three-phase refined measurements 1727
and/or symmetrical components 1728 of the refined measurement.
[0255] The application 1710 may further display alarms 1732
associated with the particular component. In the FIG. 17
embodiment, a KCL 1734 and unbalance alarm 1736 may be displayed.
However, one skilled in the art would recognize that any number of
alarms or other notices could be displayed within the application
1710. For example, if the component displayed in the application
1710 were a bus bar or node, the alarms could comprise voltage
consistency alarms or the like.
[0256] As shown in FIG. 17, the KCL alarm may 1734 be shown as "OK"
indicating that the measurements 1721 and 1723 satisfy KCL, and the
unbalance alarm 1736 may indicate an unbalance condition at the
branch.
[0257] It will be obvious to those having skill in the art that
many changes may be made to the details of the above-described
embodiments without departing from the underlying principles of the
invention. The scope of the present invention should, therefore, be
determined only by the following claims.
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